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JOINT UNDP / WORLD BANKENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP)

, a f f PURPOSE

The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) waslaunched in 1983 to complement the Energy Assessment Programme, establibhed three years earlier.ESMAP's original purpose was to implement key recommendations of the Energy Assessment reportsand ensure that proposed investments in the energy sector represented the most efficient use of scarcedomestic and external resources. In 1990, an intermational Commission addressed ESMAP's role forthe 1990s and, noting the vital role of adequate and affordable energy in economic growth, concludedthat the Programme should intensif, its efforts to assist developing countries to manage their energysectors more effectieely. The Commission also recommended that ESMAP concentrate on makinglong-term efforts in a smaller number of countries. The Commission's report was endorsed atESMAP's November 1990 Annual Meeting and prompted an extensive reorganization and reorientationof the Programme. Today, ESMAP is conducting Energy Assessments, performing preinvestment andprefeasibility work, and providing institutional and policy advice in selected developing countries.Through these efforts, ESMAP aims to assist governments, donors, and potential investors inidentifying, funding, and implementing economically and environmentally sound energy strategies.

GOVERNANCE AND OPERATIONS

ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives of the UNDPand World Bank, the governments and institutions providing financial support, and representatives ofthe recipients of ESMAP's assistance. The ESMAP CG is chaired by the World Bank's Vice President,Operations and Sector Policy, and advised by a Technical Advisory Group (TAG) of independentenergy experts that reviews the Programme's strategic agenda, its work program, and other issues. TheManager of ESMAP, who reports to the World Bank's Vice President, Operations and Sector Policy,administers tne Programme. The Manager is assisted by a Secretariat, headed by an ExecutiveSecretary, which supports the ESMAP CG and the TAG and is responsible for relations with the donorsand for securing funding for the Programme's activities. The Manager directs ESMAP's two Divisions:The Strategy and Programs Division advises on selection of countries for assistance, carries out EnergyAssessments, prepares relevant programs of technical assistance, and supports the Secretariat on fundingissues. The Operations Division is responsible for formulation of subsectoral strategies, preinvestmentwork, institutional studies, technical assistance, and training within the framework of ESMAP's countryassistance programs.

FUNDING

ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nationsagencies, the European Community, Organization of American States (OAS), Latin American EnergyOrganization (OLADE), and countries including Australia, Belgium, Canada, Denmark, Germany,Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal,Sweden, Switzerland, the United Kingdom, and the United States.

FURTHER INFORMATION

For further information or copies of completed ESMAP reports, contact:

The Manager or The Executive SecretaryESMAP ESMAP Consultative GroupThe World Bank The World Bank1818 H Street N.W. 1818 H Street, N.W.Washington, D.C. 20433 Washington, D.C. 20433U.S.A. U.S.A.

TUNISIA

POWER EHFICIENCY STUDY

FEBRUARY 1992

ESMAP Operations DivisionThe World BankWashington, D.C. 20433

I This document has restricted distribution. Its contents may not be Idisclosed without Government, UNDP or World Bank authorization.

FOREWORD

This study, which was carried out at the request of the Tunisian Electricity and GasUtility (STEG) in agreement with the Inustry and Energy Division of the Bank's Maghreb Department,was seen as a challenge from the begimring. STEG has good performance compared to that of mostutilities in developin countries, with transmission and distribution losses of about 13 to 14% comparedto 30 to 40% for many utilities of the same size.

In addition to reduction of network losses, the study identifies technical, organizational,and Institutional changes that would increase the overall efficiency of Tunisias power system, andrecommends the measures and/or additional studies needed to implement the proposed changes.

This study was financed according to a special grant procedure, the "Trust Funds Extended Agreement' with the assistance of Mrs. J. Ferry of the Multilateral Aid Division of the FrenchForeign Ministry.

The study was carried out within the framework of a contract between ESMAP andBlectricitd de France (EdF, the Consultant), with the active pat-cipation of a task force composed ofrepresentatives of the relevant STEG departments, coordinated by the Planning and General StudiesDepartment, on behalf of STEG Management. fhe preliminary report of the study was examined at ameeting of STEG's Board of Directors on November 6, 1990, and a number of the recommendationsma4e in the report were adopted.

The EdF team members were: Messrs. Henri Boyd (project manager), Gerard Aubeat(generadon specialist), Jean-Pau Barret (transmission specialist), Jean-Frangois Bruel (computerdistribution specialist), Raymond Sinus (distribution operation specialist), Marie-Line Marcin (technicaldistribution specialist), Olivier Gourlay (customer management specialist), and Alain Polvent (customermanagement specialist).

The STEG task force members were: Messrs. HEdi Turki and Hassen Mamud(Planning and peneral Studies Directorate), Messrs. Mahmoud Lakhoua, Mekki Ayed, Chekib BenRayana, Lamjpd Fekih, Mohamed El Kamel (Operations Directorate), Messrs. Khaed Hammou, HEdi,Turki, Chedl Jeddi, Taoufik Barbouche, Belgacel:. Ghariani (Distribution Directorate).

Noureddine Berrah (Senior Economist and task manager, ESMAP) supervised the project, and wrote thbisreport, basing it on the reports submitted by the Consultant and on the comments of the STEG task foc.F. Jouve (Power Engineer, ESMAP) contributed extensively to the final preparation of the report

ACRONYMS AND ABBREVIATIONS

AME Agence de Mattse de l'EnergieBCC Bureau central de conduite (Distribution Control Center)BDM Bureau des methodes (Procedures Department)CAO Consumption ascertained during operationCL Core lossesCOMELEC Comite maghrdbin de I'electricit6DD Distribution DirectorateDPWT DEpartement des techniques gdn6rales (Technical Facilities Departmet)EdF ElectrlcitE de FranceGT Gas turbineGTD Gestion technique des ouvragesHHV High heating value of fuelHR Heat rate (actual)HV High voltageJL Joule lossesLV Low voltageMSI Mise en service industrielle (Commercial Operation)MV Medium voltageNORDEL Nord Electricit6OBC Optimum base consumptionOD Operations Directorate (Direction de l'exploitation)SME Service des Mouvements d'FnergieST Steam turbineSTEG Socit tunisienne d'dlectricitW et du gas (Tunisian Electricity and Gas

Utility)tan phi Tangent of power factor angleUCPTE Union de coordination des producteurs et transporteurs d'electricitdVHV Very high voltage

ELECTRICITY MEASURES

GWh Gigawatt hourI Joulekcal kilocalorykV kilovoltkVA kdlovolt ampereskW kilowattMi mega jouleMVA megavolt ampereMW megawattTi tera jouletoe ton of oil equivalentV volt

CURRENCY BQUWIALNT

1 US$ z 0.9 Tuniian Dinar

FISCAL YEAR

January 1 - December 31

TABLE OF CONTENTS

SUMMARY ......................... i

]INTRODUCTION . 1

Organizational Structure of the Tunisian Electricity and Gas Utlity. 1Demand Growth .. ... . 2Study Objective and Methodology ............................ 2Local Participation and Skills Transfer ...... 3Report Organization. 4

II. ELECTRIC POWER GENERATION .5

Steam Turbines.... 7Heat rate monitoring .... 7Analysis of deviaions.... 9Setting up efficiency monitoring in the STEG plants .... 12Unavaiability rates .... 13Maintenance . . ...................................... 14Inventory management ................................. 16

Combustion Turbines .................................... 17Heat rates ......................................... 171vfahiteiaiice .... 17Unavailability . . ..................................... 19

Hydropower Generation ...... ............................ 19Efficiency/availability . . ................................ 19Maintenance . . ...................................... 20

Conclusions and Recommendations ............................ 20Short-term recommendations .............................. 21Medium-term recommendations ............................ 21

M]. TRANSA>ON . ........................................ 24

Simulation of Transmission Network Operations ... ................ 24Actions Needed to Reduce Losses ............................ 26STEG NetworkControl ................................... 26

Voltage levels .................... .......................... 26Compesaion ... 27

Operation ........................................... 29Additional Actions Needed to Improve Transmission Network Efficiency .... 30

14~~ ~ ~ ~ ~ . . .. 3- T"ifins ...................................., ......... 32

Iierconviicton .. . .... ............. . 32

IV. DISMUBTION........... 34

Data Collection and Loss Assessment Method ......... 35Status of available data .. ....... ...... 36Recommeniations .... ...... ..... 36Loss assessment method............ 37

Reduction of MV Nework Losses. 38Assessment of MV network losses. 38Reduction of MV network losses. 39

Reduction of LV Network Losses .... ... 41Assessment of LV network losses. 41Reduction of LV network losses .... 42

Assessment and Reduction of Losses from Transformers . .45Losses in the HV/MV taunforners. 45Reduction of losses in HV/MV transformers . 46Improving the transrmer utilization factor .. 47Losses in the MVLV transformers .. 48Reactive energy compensation ......... 49Reactive energy billing. 50

Additional Problems Associated with Operation of the MV/LV Networks .... 51Maintenance ..... 52Prevention of risks associated with the use of PCB ...... 52

V. CUS N MANA...ER ...GE. . 53

Metering .... 53Unmetered consumption. . . .. 53

CustomerBilling ... . .... 57Processing new customers... 57Meter reading. . . ..... 57Monitoring of special-tariff customers . . ..... .58

Billing procedures and correction of anomalies . . . 58Distibution of bllls . .... S.... . 59

DebtRecovery. . . .. 59Tadff Policy .... . ..... 62

'W. CONCLUSIONS ....... 63

Main Actions Proposed......... 63bpact on theEnvironient.. 64Power Conservation at the Level of Final Use ..... .................. 64

I S OG Organizational Structure ................................ 662 Calculation of Losses ...................................... 683 Equivalence Between the Inmediate Rate of Return and the Internal Rate of Return 874 Heat Rates of the Steam Thermal Plants .......................... 885 Efficiency Monitoring ...................... ....... ,.. 946 On-Line Monitoring of the Operating Efficiency

of the Fuel-Buming Thermal Power Plants 997 Unavailability Rates and Availability Statistics for Conventional Thermal

Power Units ...................... ................. 1078 Standard Maintenance Cone pts .. .I ................. ........... 1099 Load Flow Calculations - Hypotheses and Summary of Results ........... . 11210 Impact of Compensation on Loss Levels ........... ............... 11611 Reactive Power Compensaion Survey ............................ 11912 Economic Analysis of Compensation ............. ................ 12313 Selection of Network Sample ................................. 12714 Cross-Section Change ...................................... 14215 Transformer Operation in the HV/MV Substations ...... .. ........ ... 15416 Guide for Preparing Maintenance Procedures ............ ........... 155

TABLES

I Reduction of MV Network Losses ....... ....................... vi2 Reinforcement of the LV Network .................. vii

1.1 ElectricityBalance ........................................ 22.1 STEG Generating Equipment in 1991 ................. 62.2 Steam Plant Heat Rates in 1988 ...... ... ...................... 82.3 STEG: Combustion Turbines (1988-1990) ......... .. .............. 184.1 Key Features of STEG Distribution Zones ......... .. .............. 344.2 Network Losses: MV Sample ............... .................. 394.3 Reduction of Losses from MV Networks .......................... 414.4 Peak Power Losses: LV Feeder SanIple .......... .. .............. 424.5 Estimated Costs of Upgrading the STEG LV Network to 220 V ..... ....... 434.6 Network Reinforcement: LV Feeder Sample ....................... 444.7 Reinforcement of the LV Network .............. ................ 444.8 Losses in the HV/MV Transformers ........... .. ................ 464.9 Losses in the MV/LV Transformers ............................. 484.10 Savings Achievable by Reducing the Inventory of MV/LV Transformers .... .. 495.1 Change in Debt Due to STEG ................................. 606.1 Main Actions Proposed ..................................... 63A2.1 SummuyoflInvestmentsinMVSubstations .............. 77A2.2 Summary of nvestments MVlLV Substations ..................... 78A2.3 Summary of Investnents ia LV Substations .......... .............. 80A2.4 Annual Cost of One kW of Peak Losses .......................... 84

A2.5 Total Annual Cost of one kW of Core Losses in the Transformers .......... 85A2.6 Annual Cos: of one kW of Losses ............. . ....... . ., .... . 86A3. 1 Conversion of Immediate Rate of Return into Internal Rate of Retrn ........ 87A5.1 Sample Variations in Operating Parameters and their Effects

on the Heat Rates of a 125 MW Unit .... .................... 95A6.1 Measurements Needed for Efficiency Monitoring of the Thermal Power Plants 99A6.2 Cost Estimate for Installation of an Efficiency Monitoring System

for Two UJnits .......................................... 101A7.1 Unavailability Rates and Availability Statistics for Conventional

llermal Power Units ...................................... 108A9.1 Nodes: Active and Reactive Power ...... ....................... 112A9.2 GeneratingSftData ...... ..... , 113A9.3 UNOM ± 10% ........... 114A9.4 Generating Units Expected to be in Operation in 1993 ........... ....... 115AIO. 1 Perc§ntage Losses on STEG's HV Network Only (evening peak) 116A10.2 Percentage Losses on STEG's HV Network Only (morning peak) . .117A10.3 Percentage Losses on STEG's HV Network (night trough) . .118

A;l.1 List of 150 kV and 90 kV substations for which tan phi is greater than 0.5 .. 119Ai1.2 Compensation Required by Substation to Bring tan phi back to 0.5 . .120

A11.3 Measuring the Effect of the Proposed Additional Compensation. 120A13.1 heMVVLVoDistributionNetwork. 128A13.2 Technical Distribution Ratios .. 129A13.3 Regional Distribution .. 130A13.4 Network Development. 130A13.5 Sales of HV/MV Power by Sector .... 131A13.6 Power Sales to HV Subscribers. .. 99 131A13.7 Def£nition of the zones ........ .. 133A13.8 City of Tunis District, source station: Tunis South ... . ................ 135A13.9 City of Tunis District, source statn: Tunis Center . .. 136A13.10 City of Tunis District, source stati(n: Tunis West I ................... 137A13.11 City of Tunis District, source station: Tunis West 2 .... 138A13.12 City of Tunis District, source station: Tunis North .. . . 138A13.13 City of Tunis District, source station: Zharouni . .. 139A13.14 Nabeul District, source station: Hammamet ... 139A13.15 Nabeul District, source station: Grombalia ... .. 140A13.16 Nabeul District, source station: Korba .... . . 140A13.17 Interdependent Criteria, City of Tunis District .. . 141A13. 18 hiedepntde Criteria, Nabeul District .. . 141A14.1 Investment Costs for the Various Conductor Types ..... .. . 143A14.2 Reconductoring of the Haouria MV Feeder (Nabeul District) ... 144A14.3 Reconductoring of the Belli MV Feeder (Nabeul District) . . . 145A14.4 Reconductoring of the Lakmes MV Feeder (Siliaaa District) . .. 146A14.5 Reconductoring into 352 Alu - Threephase Network B2 . . . 148A14.6 Reconductoringinto 702 Alu - Tbree-phase Network B2 . .. 149A14.7 Reconductoring of the El Djazira Feeder, City of Tunis District . . . 150A14.8 Reconductoring of the Enzzitouna Feeder, City of Tunis District .. . 150A14.9 Reconductoring of the Onas LV Feeder, Ezzahra District .. . 151

A14.10 Reconductoring of the IndEpendance LV Feeder, Ezzahra District .......... 151A14.11 Reconductoring of th K a Feeder, Ezzahra Dbtraet .D ct................. 151A14.12 Reconductoring of the Ecart Nord Al LV Feeder, Nabeul District .... ... ... 152A14.13 Recondutoring of the Ecart Nord A2 Feeder, Nabeul District ........ ..... 152A14.14 Reconductoring of the Ecart Nord A3 Feeder, Nabeul Distict ............. 152A14.15 Reconductorlng of the Ecart Nord A4 LV Feeder, Nabeul District ..... ...... 153A14.16 Reconductoring of the Kaounia LV Feeder, Nabeul District ......... ..... 153A14.17 Reconductorlng of the Karsoline LV Single-Phase Feeder, Nabeul District ..... 153A15.1 List of Substations for which it Is more Economica

to put only one HVlMV Transformer into Service .......... ......... 154

FGUPeS

1 Load1DurationCCurve, 1989 .. ... ... ...... 712 Calculationof AnnulFuel Cost . . ... ......... . 733 HeatRate Vaiation due toShutdownofthcFeedwaterSystem ............ 984 ¶h eNetworkin 1989 ...................................... 1215 nhe Networkby 1993 ............................... . ..... . 122

MACA

]BRD 23592

EXEUTIVE SUMMARY

1. In the past few years, the Tunisian Electricity and Gas Utility (STEG) has madesigniflcant progress in improving its operations and reducing losses in the electricity network. Fuelconsumption per GWh produced has been reduced by about 23% in five years (from 309 toe/GWh in1985 to 278 toe/GWh in 1987 and 251 toe/GWh in 1989) and the overall efficiency of the transmissionnetwork has been improved ty about 2.5% in five years (from 83% in 1985 to 85.5% in 1989).1/

2. The diagnostic study carried out as part of the joir.t World Bank/UNDP Energy SectorManagement Assistance Programme (ESMAP), with the active participation of STEG experts and supportfrom the Industry and Energy Division of the Maghreb Department (EM2IE), has shown that:

(a) because of the progress STEG has achieved in electricity network operation andin customer management, the power loss rate in Tunisia is among the lowest tobe fbund in the developing countries, especially with regard to nontechnicallosses; however, preserving this achievement requires sustained efforts toImprove management, rigorous application of existing procedures, andimprovement of the statistical system and efficiency monitoring;

(b) additional savings can be made by introducing more advanced operating methodsand by making economically justifiable power efficiency investments both ingeneration (heat rate reduction in the power plants) and in transmission anddistribution (reduction of technical and non-technical losses).

3. PoE w gia1er. The audit of generation activities confirmed STEG's eaicientperformance in this area, despite certain weaknesses. The principal recommendations of the study entail:

(a) in the short term, (i) continuing rehabilitation and renovation or me old steamthermal plants so as to improve availability and efficiency; and (ii)standardization and upgrading of statistical data on fuel consumption and ongenerating unit availability;

(b) in the medium term, (i) minor organizational changes to ensure bettercoordination of operation and maintenance; and (ii) introduction of moreadvanced management methods to improve the efficiency of existing and futuregenerating units, especially as the utility is still faced with a high tempo ofinvestment.

4. Rehabilitation and renovation of old thermal power plants. STEG has begun to renovateits old steam thermal plants, which has significanty increased the efficiency of the units involved. Themission recommends that STEG continue these actions and that it establish a rehabilitation and renovation

I/ 7he overjky of de network is dnd as dhe ratio of energy billed to energy sypped, measured at theplantentale.

- ii -

program for all the units in the La Goulette and Ghannouch power stations. STEG's experience hasconfirmed the conclusion ESMAP has reached In a number of countries, that well-planned investmentsin renovation and rehabilitation have high economic rates of return. The investments made at GouletteI to improve control systems and the installation of pre-heating equipment were recovered in nine monthsthrough energy savings alone, without taking into account the fact that renovation of the equipmentextends its life and Improves its availability, and hence enables investment in new generating units to bedeferred.

5. Improving data quality and availability. Tbis effort should be part of the overall reviewof the utility's statistical system and its computer master plan, after the Planning Directorate hascompleted an audit. However, certain measures, such as improving gas metering to make therelationships between the Gas Directorate and the Operations Directorate more transparent, andstandardizing and improving the data on heat rate and generating unit availability, (the plant operatorsrecord these data monthly and annually), are urgently needed and essential to improved monitoring ofthe performance of the generating system.

6. Orgmioag measures. The mission recommends three minor structural changes to theOperations Directorate to improve coordination and prepare for the introduction of more effectivemaintenance methods and procedures:

(a) create the position of manager for steam turbine generation with the same levelof responsibility as for existing positions related to gas turbine and hydropowergeneration. Creation of this position would improve coordination andstandardization of procedures between the power plants and would strengthen theOperations Director's role as the overall manager and arbiter;

(b) establish a "Procedures Department" (Bureau des Methodes - BDM) to enhancecoordination of operation and maintenance of the combustion turbines. Thisdepartment could be integrated into the existing BDM for the steam thermalplants and located at La Goulette so as to benefit from the assistance of theTechnical Facilities Departnent (DIpartement des Techniques G6ndrales -DPITG); and finally

(c) create a small unit (startng with one engineer and one technician), perhapswithin the BDM, to develop maintenance procedures and coordinate and monitortheir implementation through the maintenance programs.

7. ImW1empentatiqn of online efficiency monitoring of the steam turbines. The reportrecommends study and implementation of computerized online efficiency monitoring of the steam turbinesbased on continuous comparison of the performance parameters obtained with unit reference parametersto ensure that fuel consumption approximates optimum base consumption (OBC) as closely as possible.The economic return on this Investment is high since the investment payback period, even usingconservative cost and benefit assumptions, would be around 11 months (see para. 2.50).

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8. jbpxduction of wconditional" or predictive maintenance. The report recommends thestudy and introduction of "conditional" or predictive maintenance programs. STEG could use suchprograms, which are increasingly being adopted in the developed countries, for each component or familyof components, using STIEG in-house, centralized research resources (DPTG). ESMAP's experience inthis area shows that such projects have very high internal rates of return, for companies less efficient thanSTEG. The estimated reduction in STEG's maintenance costs is around 8% to 10%, i.e., a saving ofbetween US$1 million and US$1.25 million in 1990 and of between US$1.2 million and US$1.5 millionin 1995.

Trapsmiasson

9. Simulations of the transmission network lead to two conclusions (see paras. 3.2 to 3.4):

(a) in all operating systems examined, theoretical power losses are about 1% to1.2%, or only about one third of actual identified losses in 1989, which werearound 3.6%. The reason for this discrepancy needs to be found: it couldoriginate from metering irregularities and/or from failure to account for thesubstations' own power consumption, or to a discrepancy between the model(reference condition, electrical characteristics of lines and equipment) and actualoperating conditions;

(b) the system power factor is abnormally low during the day, particularly during themorning peak period, around 0.82% in 1989 for the situations studied. UnlessSTEG implements reactive power compensation, the situation will grow worseover the medium term.

10. Analysis of the causes of technical losses in the network highlighted the need for threekinds of action:

(a) increasing the network operating voltage levels and selective reinforcement of thereactive power compensation equipment;

(b) improvements in the operation and maintenance of the transmission network; and

(c) progressive actions that contribute indirectly to increasing the efficiency of thetransmission network, viz., strengthening the planning function and makingorganiational changes.

Voltaye ungrading

11. The simulations show that raising the maximum voltage level from 210 kV to 225 kVreduces active power losses by some 2 MW for a load of 1,000 MW (peak demand in 1993). Thisupgrade, valued at the incremental cost for a kW of energy at the HV transmission level, produces asavings of about TD 400,000, or US$444,000, per year.

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12. Ihe mission therefore recommends the study and determination of suitable criteria tomonitor and control the performance of the network, thus detecting weak points and anticipating lowvoltage conditions that may arise. This would allow the operators to take timely measures to restorevoltage levels and maintain satisfactory service quality, and would avoid the risks of unplanned loadshedding. The benefits due to improved service quality are hard to quantify but experience in othercountries has shown that a 5% drop in nominal voltage at customer level leads statistically to a 2% dropin load. Poor service quality causes economic losses to customers and financial losses for the utility (seeparas. 3.7 to 3.10).

13. The study showed that the system power factor is abnormally low, especially during themorning peak period, and that the situation will worsen unless measures are taken to enhancecompensation by:

(a) using the gas turbines at Tunis Sud as synchronous compensators, and/or

(b) installing additional capacitors: in 1989, for example, 120 to 130 Mvar wasneeded to improve the power factor from 0.8 to 0.9. By 1993, 211 Mvar wouldbe needed to maintain tan phi, the reactive to active power ratio, at 0.9 (seeparas. 3.19 to 3.21).

14. Reducing transmission network losses cannot by itself guarantee a return on investmentsin compensation equipment, but such investments help to improve voltage control and, hence, to improveservice quality and network reliability. Since detailed studies to evaluate all the advantages ofcompensation are beyond the 3cope of this study, the mission recommends that STEG undertake a studyto identify, for all voltage levels, the number and types of compensation devices needed to ensuresatisfactory network operation from a technical standpoint while keeping investment costs to a minimum.

Improving operations

15. The operation of STEG's transmission network is satisfactory, but to reduce the effectsof insulator flashover, which is most marked in the 150 kV lines, and to reduce outages attributable tochemical and marine pollution, the mission recommends that STEG:

(a) undertake a study to measure cable sag and conduct a technical and economicanalysis of the need to re-tension some cables; and

(b) improve insulator cleaning procedures in areas where frequent flashovers occurdue to chemical and marine pollution, and study the feasibility of introducingprocedures for hot line cleaning of insulators. In particularly polluted areas, itis advisable to introduce special types of insulators, at least on an experimentalbasis, and to undertake detailed technical/economic studies on the introductionof Gas Insulated Stations (GIS).

QxmAIUaLmand ngi

16. To betr fit the management responsibilities for operation and customer management tothe technical demarcation between the transmission and distribution functions, two minor orgaiationalchanges are recommenhied:

(4) divide the responsibility for management and operation of the protectveequipment according to the functiona difference between tranmission anddistribution; and

(b) create a unit within the Operations Directorate to take over the management ofhigh-voltage consumers from the Distribution Directorate.

17. The quality of ntwork analyses should be improved and they should be integrated intoperiodic power system planning studies. Por this purpose it is necessary to:

(a) provide additional data processing resources for the Planning Directorate;

(b) improve the methodology used in economic appraisal of investment projects; and

(c) syste and conputerie both data collection and statistical analysis.

18. Investigation of the operation of the Maghreb interconnection is beyond the scope of thisstdy; however, it should be noted that the present interconnection between the lviaghrebian networks isnot being used opimally, essentially beause tariff rates for the energy exchanged are not set on the basisof economic costs and there is no regular coordination and ongoing exchangq of data between the threenetworks that are curreatly interconnected.

19. The mission reommends that COMELEC (Comit6 Maghrdbin de I'Electricite) make aneconomic and teenical study to determine whether it is economically feasible to set up a coordinationand control center, based on a preliminary review of international experience in regional interconnections,such as that of NORDEL (Nord Electricit6) and of UCPTE (Union de Coordination des Producteurs etTransporteurs de l'Electricit5).

20. In view of the great extent and diversity of STEG's distribution network, the studyfocussed on three representative network samples, selected in three areas according to the followingcriteria:

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(a) network efficiency as defined by the ratio of energy billed to energy supplied;

(b) the ratio: km of MV lines/km of LV lines (see para 4.4).

Network data collection

21. A smal portion of the data necessary for loss reduction and planning studies was eithernot available or not sufficiently reliable or consistent. Therefore, STEG must give priority to:

(a) continuing to build network data bases (structure, technical characteristics, loads);the existing database system, Gestion Technique des Ouvrages (GTD), should beimproved to include all relevant facilities and their components (equipment);

(b) maintaining standardized network mapping (possibly computerized);

(c) Improving the data system: collection, circulation and filing of network data andmeasurements, particularly in the case of the Distribution Control Center (BureauCentral de Conduite - BCC); and

(d) continuing and expanding studies to measure voltage drops and current losses onthe network, within the framework of the GTD system.

Reducing MV losses

22. The esdmated loss factor for the entire STEG network is 3.5% of total peak power. Itcan be reduced to aut 3% . network reinforcement, i.e., by increasing the conductor size on 639 kmof MV lines (see paras. 4.19 to 4.23). The overall cost of the investment is estimated at TD 3.6 million,or about US$4 million. The investment payback period is 3.3 years on average, but analysis of thesample shows hat about 20% of the improvements have payback periods of less than two years; theseshould be implemented fist (see pan. 4.25).

Table 1: REDUCTION OF NV NETWORK LOSSES

Area 1 2 3 f STE6 network

Length of NV network to be relnforced tkm) 103 536 None 639Cost (thousnd TO) 996 2627 - 3623Peak load gain (kid) 894 2190 - 3084Financial savings (thousand TO) 322 790 1112Payback period (years) 3 3.3 - 3.3

J/ See pars. 4.22(c): the special case of the Chargufa feeder llne.

vii -

23. The estimated loss rate for STEG's LV network is about 6.8%, but it could be decreasedto 3.8% by reconductoring 944 km of LV lines, or about 3.1% of the total LV network, for a total costof some TD 8 million, or about US$9 million. The payback period is about 3.7 years.

Tablo 2: REINFORCEMENT OF THE LV NETWORK

Area 1 2 3 P/ STEG Network

Length of LV Network to be reinforced (kin) 832 - 112 944Cost (thousand TD) 7184 - 962 8146Peak toad gain (Id) 3950 754 4704Financial savings (thousand TO) 1862 - 355 2217Payback period (years) 3.9 - 2.7 3.7

The report recommends that this program start with the reconductoring of those network scions withthe highest return (see para. 4.30).

24. The Tunis city networks are a special case because reconductoring these lines would bemore expensive and less cost-effective. However, it is essential to continue upgrading the voltage from110 V (LI) to 220 V (2) and to complete this program quicldy (two to three years), since the indirecteconomic effects of this standardizaton on distribution equipment cost, on the one hand, and on the costof household electric appliances on the other hand, are greater than the savings to be obtaned fromreducing losses.

.Reducintranfmer lss

25. Although losses in the HVIMV transformers are low, about 0.69% of peak demand,savings of about 3 GWh and 346 kW of peak demand, equivalent to TD 126,000, or about US$140,000,can be achieved merely by changing the operating practice of the 8 HV/MV substations. It is thereforerecommmended that STEG:

(a) during nonral operation, keep only one transformer energized in the eightsubstions where this is clearly economically advantageous and technicallyfeasible, without installing any additional switching equipment. The anticipatedsavings from reduced core losses are about TD 78,500 (US$87,000) per year;

(b) carry out technical/economic studies for the five substations where improvementsare necessary, comparing the savings of about TD 47,000 a year (aboutUS$53,000) from reduced losses with the cost of the work required (remote-controlled HV switches in particular).

26. Extrapolation of the results obtained from the MV/LV transformer study sample gave aloss rate of 3.3% at peak load. Reducing this percentage wiJl require a better adjustment of the size of

-viii -

each transformer to the peak load. Ihe technical/economic study of the 10 kV network indicad that itwas economic to Interchange about fifty 500 kVA transformers and fifty 630 kVA transformers, for atotal cost of about TID 11,000 (UJS$12,100) and an anmal saving of about TD 6,000 (US$6,600), i.e.,the payback period is less than two years (see para. 4.46). The standardized transformer sizes STEG hasadopted produce significant threshold effects. The 400 kVA category appears to be the least cost in somesituations; therefore, STEG should reconsider its announced intention to phase out its use.

27. It shoud also be noted that reducing the stock of transformers from 10% to 5% of totalcurrent inventory (about 1,000 units) would reduce associated costs (for storage, acquisition and deliery)by at least around TD 263,000 (US$290,000) per year.

Customer Managemen

28. Since 1986, STEG has made major improvements in customer managemet, aimedmaiyat reducing technical losses and recovering debts. It has:

(a) trained its personnel in the detection of fraud;

(b) checked all the LV meters between 1986 and 1989 and monitored them sincethen;

(c) made an annual check of all MV meter records; and

(d) made a significant effort to reduce customer connection time and recover debts.

29. These actions have significantly improved STEG's overall performance, making it oneof the best power utlities in the developing countries. STEG's nontechnical losses are esmated at lessthan 4% of total power sales.

30. The mission's recommendations are designed to complement STEG's progrm andconsolidate these achievements by:

(a) enhancement and rigorous application of existing procedures; and

(b) adoption by STEG of management techniques and methods used in moreadvanced power utilities.

31. STEG's meter organization and meter reading procedures are effectie and miimize therisks of fraud. They are based both on encouraging company personnel to combat faudulent pracdtes,

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and on deterrence of these practices, supported by legal provisions that clearly equate fraud with the theftof electricity.

32. Experience in a number of countries shows that electricity theft spreads rapidly and isdifficult to eradicate once it becomes pervasive; it is therefore recommended that STEG:

(a) ensure that procedures are strictly applied and strengthen deterrence throughorganizing swift, targeted meter monitoring campaigns, based on statisticalanalysis of metering data in areas where problems are frequent; and conductingmonitoring campaigns in response to a specific type of problem or a specificclient category (e.g., large customers, poor payers, those with billingirregularities, etc.). To increase their deterrent effect upon consumers, thesecampaigns should be well publicized in the appropriate media;

(b) increase procedural monitoring of the billing and data processing that is done atthe end of each billing cycle to detect irregularities in consumption due tometering evasions or metering irregularities;

(c) introduce computerized mana,ement of the meters in service;

(d) encourage installation of meters on the outside of plant buildings; and

(e) where justified, gradually introduce electronic metering, which is more reliableand more adapted to monitoring multiple and complex tariffs.

33. Customer billing is done automatically in two computerized centers, Tunis and Sfax.Billing is generally satisfactory, since STEG agents deliver the statements to customers within three tofive days. It is recommended that STEG:

(a) use a stricter management criterion for signing on new customers (see para.5.17); and

(b) begin distributing bills by mail once the quality of the postal service, tested bypilot mailings, is considered to be adequate for STEG's needs.

Debt recver

34. lhe management measures STEG has taken have enabled customer arrears in paymentto be reduced from the equivalent of 64 days of average turnover in 1984 to 49 days in 1985 and 30 daysin 1988 (see para. 5.26). Three-quarts of the arrears are attributable to government agencies, localauthorities, and public corporations.

x

35. The mission recommends that STEG establish a long-term objective of reducing arrearsto the equivalent of 20 days of rAverage turnover by:

(a) focusing on enhancing recovery of debts from public and parastatal organizationsby: improving the budgeted prepayment system to avoid difficulties in collectingthe balance of the debt at the end of the year (see para. 5.25); statistical analysisof the power consumption of clients using this system, which would enable themto better forecast their electricity consumption when they prepare their annualbudgets, and extending budgeted prepayment practices to the local governmentbodies, adapting the system as necessary to meet their special circumstances;

(b) encouraging professional clients, particularly the govermnent corporations andagencies, to pay their bills through direct debits from their bank account; and

(c) incorporating Into the computer applications now being developed an indicatorthat would monitor the level of debts outstanding after 20, 30 and 55 days. Suchan indicator would improve information on the customer arrears and increasepersonnel awareness of the need for quick debt recovery.

CQoncusion

36. The main investment programs and actions proposed are summarized in the table below.

lkbe 3: PROPOSED ACTIONS

Annuat Pavback Rate ofActions Costs savings period return

(USS 000) CUSS (000) (years) tX)

1. Set up continuous ecornmic efficiency 1,000 1,250 < I > 100monitoring of steam turbines

2. Reinforce NV network 3.300 1.300 2.5 40

3. Reinforce LV network 9,000 2,500 3.6 28

4. Better management of NV and LV transformers Low 150 1.2

5. Decrease the customer portfolio to 20 days Low or 780 -

turnover nil

6. Other ifprovement actions: maintenance, Low or .1,720technical and financial management nit

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37. Estimates of the economic impact of power plant emission reduction programs vary ina wide range, I to 10, according to existing studies. However, additional environmental benefits fromthe proposed power loss reduction programs can be conservatively estimated at US$7 million, that isabout half of the total investments needed for their implementation.

38. To complement this supply-side program, it is recommended that STEG set up a taskforce to:

(a) study, in coordination with the Agence de Maltrise d% l'Energie (AME), thepromotion of well targeted end-use electricity conservation programs that areeconomically and financially viable for the utility, the consumer, and the localauthorities; and

(b) participate in their imp ,nentation through better customer information, possiblyin associaion with partners, local authorities, and/or private promoters Interestedin promoting such programs.

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C I .1 |b:t i

0 g~i il l Ziiil a;i

t § 0f*§1 ii }1iftx 11 S

I Ii I i JjJ z .iH@d

[d di i 1 *1 1

MAW _ - 1

Amg one~~asebtion Mlswtabs ued bswam Paubsego1 1. Pagubusme,iuee. Oste a p_dlbeof -mag.ref So 1 gdb , ,t , _perathus

(Or4nte an M.e~ a uie Dpt_~~~~~~~~~~~e t- fbe _el s.ubh =dar

t W m* we ub Ofe p _ 0 t. e_aar Aam s _mSW aumw dr trs q*en* usab to, i ee oalatoma.

Tr.WWAdeslm 3. PresAde netle* oeIt 1nseIIhn. Stdo teauebof plNaci Reduction Ofloen medaputUnre*umA, - eser at HYdens' wfedUm. hiprve operating uelbIty. em 130 Mvm. Swuw of hiFOUMty owvoftemof gams' OfWItWis nWm be ebtine tluarhotaiefor syncwwonn cowan. -nl network -patm

Adliorn elonmdtet study (2 manw-mownftl.

4. Inuprw operaton. - ineasuranes* of wiftoag drops. WMN anow network operation atea+reeclktlon ofthe Problem of Ihigher voltae leve (210 to 225 kV

polluion of the InLsultors upgrade roduces hues. by 2MW.VIN iurSOM newvotk taeNbilty.

5. brnprov demand forecsastI VWd Valorizatio study of demanid More detaied plannin studies.planning, forecasting deficiencies. more effiient maagmemen of the

Establishment and ronortorin of a genrawtit ngwits.-tth reser"Creation of e' tltt schedule for-wna power.Additioal equipmnent for data

^ _ _ d~~~~~~~~oleto and storage

conection 9w _torms. k prowd efficiency of heS. Study the advisabilty of setting FeasIbIty study. Interconnection betwee the Maghsebup a Coordinaton and Cotrl country networs

4technical) 7. Redue trnfomer vnwto. Effectv inv ry oensus. Estimted savins on fixed nveevmet The purpos of th action Is to rducecosts TD 1.5 nionm (US$11.7 millon). nventory to 5% of tota stoci (aboutSavings on associae costs: 1000 unts)To 263,000 (US$290,000) per year.

S. Provide noetwork ocropnsetlon. Study of the advisabIlIy of placing Reduction of kBoso (WRA -80%).condensers on the MiV networh

9. Reconto 2nd section of Cost TD 8.2 million VJS$9 Mon). Reduction of Dses: ID 2 miln Reconductort of MV NWd LV lns.network (US$2.2 miflionI.

Cost ID. I11.100 mIlion Reduction of kmsqs: TD 6.50010. Intecange the MViLV (US$1 2,300). (US$7,250) pe, wowr' AdApttion of wilt sizes to urilt astransfomwna. __ __ ____

DIstribution 1I1. Improve corrputeioted data Detection of abn1ma power Monitoring of mesasuweent anoinalIes. Adept to the local context.(customerNOQOD maaeencnsu mption OPbEing Mmonioig of speed of payment ofmanagement) Wwaring sina of i. ratio of debts bhl.due accordin to the nmber f days

Cn uwied nstat* u p a 6~~~~~~~~o delay _npyet(etrcvr

-uam -ategomenageen

12. MIN custfecs by mall, cincraseod producvty. Monto the quaTaty of nd distribution.1I& Int"oduce electronic meterdng Mnor flexibl 1reponse to compolex

14. ncoragof very low Cot. The utty wc saw puR-i funds.n~eted prepayment for pa*fLeC 'pll 10uttob IS

I. INTRODUCTION

1.1 In 1986, the Tunisian Electricity and Gas Utility (STEG) initiated a program to reducelosses in the electricity network. As a result, the overall efficiency of the system has been improvedthrough reduction of:

(a) the heat rate of power stations from 309 toe/GWh In 1985 to 278 toe/GWh in1987 and 251 toe/GWh in 1989; and

(b) transmission and distribution losses from almost 17% of power supplied in 1985to 14.5% in 1987 and 1989.

1.2 It nonetheless became clear that an overall review covering the origins of losses fromgeneration to distribution, network operating methods and custownr management would enable STEG toconsolidate the results achieved. Such an approach would also make it possible to establish priorities forenhancing the overall efficiency of the power supply system: investments to be made to reduce losses,Introduction of new management methods, collection of the data needed for network control and forimproved monitoring of system performance. By agreement with the Industry and Energy Division ofthe Maghreb Department (EM2IE), the Tunisian Government decided to undertake this study as part ofthe joint World Bank/UNDP Energy Sector Management Assistance Program (ESMAP).

.rjanlzatlonalStructure of the Tunisian Electrict and Gas Utiliy

1.3 STEG is a statutory government corporation, of a commercial and Industrial nature,established by Decree Law No. 62-8 of April 3, 1962 on nationalization. This law makes STEGresponsible for the generation, transmission, distribution, import and export of electricity and fuel gasunder the supervision of the Ministry of the National Economy.

1.4 STEG has five (5) departments and ten (10) directorates which report to the chairmn andmanaging director and are responsible for operating the electricity and gas systems and managing theutility. A more detailed description, as well as the corporation's organization chart, is provided in Annex1.

1.5 STEG's Board of Directors has 14 members:

- 1 Chairman and Managing Director- 1 Assistant Managing Director- 8 directors representing the State- 2 directors representing employees-1 financial controller- 1 technical controller.

-2-

Neither consumer representatives nor any nongovernmental organizations active in the energy field or Inenvironmental protection are represented on STEG's board; if they were, more consideration might begiven to the problems that gas and electricity consumers experience and to involving consumers in thedevelopment of the sector.

penzan GrowX

1.6 From 1962 to 1989, total electricity consumption grew at a very high average annual ratof some 11%. Since 1982, the pace of growth has slowed somewvhat, but it is still substantial, about7.5% between 1982 and 1989, as shown in Table 1.1 below.

Table 1.1: ELECTRICITY BALANCE

Year 1982 1987 1989 1996

1. National production (GWh) 3174 4549 5235 7400

a. STEG 2738 4016 4562 6680b. Self-generated 436 533 673 7200

2. National consumption (GWh) 2792 4031 4605 6660

a. Detivered by STEG 2374 3544 3987 6000b. Setf-generated 418 487 618 660

3. STEG network losses

a. in GWh (Ia - 2a) 409 514 575 830b. 'n % of power supplied 17.2 14.5 14.6 13.8

Source: STEG.

1.7 STEG's medium-term forecasts show that the growth in electricity consumption will slowslightly from 1989 to 1996 but will continue to be significant, about 6% a year. Thus, to minze theinvestments required to meet future demand, STEG should consolidate the actions already taken to reducelosses and enhance the efficiency of the system.

Study objece -and meaongy

1.8 The principal aim of this study, therefore, is to analyze:

(a) STEG's three main technical functions, viz., the generation, transmission anddistribution of electricity - so as to identify the actions and investments neededto reduce the technical losses linked te the generation, transmission, anddistribution of electricity; and

- 3 -

(b) customer management, In order to reduce nontechnical losses - which areatributable not only to meter fraud as generally understood but also to thereliability of the meters used and the utility's policy for connection of newcustomers - and to optimize the fnancial cycle by improving customer billingand the recovery of arrears in payment.

1.9 The following four tasks were carried out:

(a) a technical audit of power generation based on visits to the principal sites,wlrking sessions with power station managers and staff from the centraldepartments, a review of operating procedures, and an analysis of availablestatistical documents;

(b) technical audit of transmission based on site visits, discussions with transmissionsstaff, an analysis of operating procedures, and computerized network simulations;

(c) a technical audit of distribution based on field surveys, discussions withheadquarters and regional staff, and computerized simulations of the medium-voltage network and of a representative sample of STEG's diverse low-voltagenetwork.

(d) a review of the procedures used throughout STEG's customer management cycle,from metering and meter reading to bill collection.

1.10 Task objectives were to assess the losses in each area considered and to identify theactions required to reduce them to economically acceptable levels. To ensure the overall consistency ofthe approach and the recommendations, a preliminary study was made to estimate the incremental costsof the equipment at the various stages involved - generation, transmission and distribution -- as well asfuel costs. To ensure that the recommendations proposed would be compatible with STEG's usualselection criteria, the method used for the calculations and the results contained in Annex 2 weresubmitted to and discussed with STEG officials before the economic evaluation was made.

L-ocalartiCiaion and skills transfer

1.11 S1EG participated actively and effectively in all phases of the study: diagnosis, economicevauation, and review of the consultants' preliminary reports. The study was monitored by a task forcecomprising representatives of all the directorates involved, and coordinaed by the Planning and GeneralStadies Directorate.

1.12 Two study visits to France were organized, enabling six (6) members o the task forceto visit transmission and distribution facilities in France, to familiarize themselves vwith the network

- 4-

models used by the consultant, and, in the case of transmission, to particirate In simulations of theTunisian network.

1.13 To ensure lasting benefits from the effort undertaken to reduce losses, and to strengthenthe network analysis funk on within STEG, the study was complemented by:

(a) organization of a seminar to increase awareness of the problems of networklosses, and presentation of the analytical methods and models needed for lossreduction; and

(b) transfer of a PC-computer model for study of the distribution networks, andtraining of engineers in its use.

Action (b) was made possible thanks to STEG's participation in financing the local costs of the project.

NM rgan1oaion

1.14 The report layout reflects the approach adopted for the study. Following a shortintroduction focusing on the background to the study and the methodology adopted (Chapter 1), fourchapters present the results of the analyses, and recommendations for reducing losses and improvingmanagement in the areas of generation (Chapter II), transmission (Chapter Im), distribution (Chapter IV)and customer management (Chapter V). Chapter VI summarizes the main conclusions of the study.

-5-

H. ELECTRIC POWER GENERATION

2.1 Installed capacity rose from 273 MW in 1972 to 1,179 MW in 1989, in three stages:

(a) Installation of a 30 MW steam turbine (La Goulette, Ghannouch);

(b) installation of gas turbines (particularly in the south) using gas from El Bormaand gas oil;

(c) installation of 150 MW steam turbines (Sousse, Rades).

The detailed list of generating equipment given in Table 2.1 (on following page) reveals that, althoughhydropower capacity doubled between 1972 and 1989, it is stll limited (about 5% of installed power).

-6 -

Tabte 2.1: STEG GENERATING EQUIPNENT in 1991

NetYear installed Maximf.brcught into capacity capacity

Plant Unit service (NW) (MW) Fuel used

1. StMtuines

Goulette 2 STI 1965 28 22 Fuel oflST2 1965 28 22 Fuel oilST3 1968 28 22 Fuel oilST4 1968 28 22 Fuel o@11

Ghannouch STI 1972 30 28 Fuel oil/GasST2 1972 30 28 Fuel oil/Gas

Sousse STI 1980 150 140 Fual nil/GasST2 1980 150 140 Fuel olI/Gas

Rades ST1 1985 160 150 Fuel oil/GasST2 1985 160 150 Fuel ol/Gas

Total ST 790 724

2. Cal turb(nes

Gharmouch GT1 1971 15 15 GasGT2 1973 22 20 GasGT3 1973 22 20 GasGT4 1983 34 30 Gas

Douchemm. GT1 1977 31 25 GasGT2 1977 31 25 Gas

Tunis South GT1 1975 22 20 GasGT2 1975 22 20 GasGT3 1978 22 20 Gas

Sfax Gt1 1977 22 20 GasoitGT2 1977 22 20 Gasoil

N. Bourguiba GT1 1978 22 20 GasoilGT2 1978 22 20 Gasoil

Netlaoui GT1 1978 22 20 .iasoitKorbe GT1 1978 22 20 Gas

GT2 1984 34 30 GasKcasserine GT1 1984 34 30 Gas

GT2 1984 34 30 GasRobbana GT1 1984 34 30 Casolt

Total GT 489 435

3. Hvdtre r

Nebeur 1 1956 6.5 Hydropower2 1956 6.5 Hydropower

El Aroussia 1 1956 4.9 HydropowerFernana 1 1958 9.7 HydropowerKesseb 1 1969 0.7 HydropowerSidi Salem 1 1983 36.0 Hydropower

Total hydropomer 64.3 20

Total Inventory 1343.3 1179

-7-

Steam Turbines

2.2 STEG's steam thermal equipment consists of the following:

(a) six 30 MW units with a single-stage turbine (Ghannouch 1 and 2; La Goulette3 and 4) or a double-stage turbine (La Goulette 1 and 2);

(b) four 150 MW units, of more recent design, and equipped with three-stage turbines(Sousse 1 and 2; Rades 1 and 2).

Because the two categories are different in age and design, there are considerable differences betweentheir reference heat rates (as determined during the commissioning tests when they were brought intoservice). The 30 MW units are rated at 2950 kcal/kWh, while the most recent 150 MW units (Radbs,using naural gas) are rated at 2350 kcal/kWh. The difference in performance between the 30 MW and150 MW units is mainly due to:

- higher steam temperature (540°C instead of 500°C) and higher pressure (145 bar insteadof 66 bar) at the turbine intake;

- addition of a steam superheater;

- an increased number of stages.

These improvements increase cycle performance and reduce the heat rate.

Re$at rate monitoring

2.3 Heat rates are regularly monitored in the plants and recorded in the operating logbooks.In the plants visited, the logbooks were up-to-date and well maintained. Monthly and annual statisticsare produced by unit, by plant, and by unit size. All deviations from the heat rates recoraied in thecommissioning tests are analyzed and included in the monthly reports, copies of which are forwarded tothe Operations Directorate (OD).

2.4 STEG's Research and Development Service is developing efficiency monitoring softwareat the Sousse plant, and intends to supply it to other plants once it becomes operational.

2.5 The software processes data on the operating parameters of the equipment, including:boiler, turbine, and alternator efficiencies, and heat rates. The parameters are currently measuredthrough brief tests at flat power outputs. The heat rate values thus obtained are compared, aftercorrection, with their reference values. It should be noted that the Rades plant has one computing device

- 8 -

per unit; these dvices print out lists of values on demand, and can perform operations such asinegration, derivation, and averaging. The La Goulette plant has on-line computing resources (the Baileymicro Z system), in the central control room for the four units.

2.6 Analysis of the heat rates obtained from the various readings on the equipment operadngparameters (aggregated in Table 2.2) ieveals that:

(a) the Soeue and Radbs plants, which account for over 80% of steam-driven insiledcapacity and about 50% of total installed capacity, perform very well. Heat rates for thetwo plants are very close to the reference values, particularly if allowance is made fordeviations due to output variations and to operating guidelines that require the fuel-buming circuits of gas fueled units to be kept heated (Rades). At Sousse, however, thevery wide discrepancies in monthly heat rates compared with the annual average shouldbe noted (see Annex 4).

(*) the performance of Gabbs is quite poor. The average heat rate for 1988 exceeds thereference value by 17.4%, a considerable difference, even allowing for the age of theequipment and variations in load; and

(c) in La Goulette, heat rates have definitely been improving since the following majorImprovements were made to the plants: (i) new boiler controls; (ii) more efficient fuelheaters and fuel pumps brought into service; (iii) riser tubes replaced (unit 2) andintermediate superheater and economizer replaced (unit 4); (iv) units 2 and 3 overhauledand turbines repaired (blades and seals).

able 2.2: STEAM PLANT HEAT RATES IN 1988

Annual heat rate Reference heat rate EffRcJ2= differecPlant (kcat/kWh) (kcal/kWh) KCat/kWh I

Sousse 1 2630 2565 65 2.52 2613 2565 48 1.9

Radbs 1 2428 2350 78 3.32 2437 2350 87 3.7

Gabbs 1 3357 2860 497 17.4

1 3215 2889 326 11.32 3215 2889 326 11.3

¢*ulette 3 3215 2958 257 8.74 3215 2958 257 8.7

Mm;g: Annual heat rates are not dSrectly ccqtrable with reference values because the tatter were measured atnominal output when delivered and thus take no account of load variations. Nevertheless the efficiencydifferences noted can be considered indicative of unit performance.

-9 -

2.7 Differences of actual heat rates from rated values are usually divided into the followingthree categories:

(a) Intnal differences due to unit control: These may result when shift teams do notrespect correct operating procedures;

(b) Internal differences due to the equipment: These are caused by the condition of theequipment (e.g. wear in some components, partial unavailability etc.); and

(c) Exen differences: These are essentially the result of meteorological changes (airtemperature, temperatre of the cooling source, etc.), which have a direct impact onperformance. Also included in this category are differences resulting from operatingprocedures imposed by the national control center (variations in load and frequent unitstart-ups seriously affect heat rates).

Internal differences due to unit management and equipment condition (maintenance) are indicative of thequality of unit operation, but operators have no control over external differences. In these cases, onlythe operators of the National Control Center can effect any improvements.

2.8 Consequently, unit performance can be described as follows:

Heat rate = Adjusted rated value+ eternal differences + internal differences due to unit management+ intemnal differences due to equipment condition + unexplained differences

As STEG's existing information system does not enable a distinction to be made between the variouscategories of difference, the following analysis of differences is more qualitative than quantitative; it isbased on visits to plants and conversaions with operators.

2.9 Itra diffaences due to unk control ad MUM training: In STEG these are minimal.Detailed inspections of control rooms and conversations with unit contol teams show that:

(a) shift supervisors and command console operators are well aware that compliance with thereference variables for the main operating parameters (steam pressure and temperatre,condenser vacuum, excess oxygen, etc.) has a positive impact on efficiency;

(b) the staff are familiar with the operating procedures, operating diagrams, and instructions,and these are kept updated;

- 10-

(c) panel equipment readings that are obviot, sly wrong or inconsistent with other parametersare reported to the Technical Service so that it can carry out repairs or recalibrate theinstruments; and

(d) on the whole, recruitment and training of operations staff are satisfactory.

2.10 However, to alleviate the scheduling problems connected with providing training andskills upgrading for the rotating shifts (who ensure round-the-clock operation of the plants), the followingimprovements to in-service training are recommended:

(a) the preparation of training packages, comprising both text and diagrams. Each packagewould deal with a specific subject (the alternator, the feedwater system, the turbine, etc.)and the complete set of training packages would constitute a body of training appropriateto the functions and level of each staff member. The packages would be distributed tothe various members of the shift teams, who would study them individually.Consequently, each team would work together to upgrade the group's expertise. Thedepartment superintendent would be responsible for the overall management of thetraining program; and

(b) training center instructors should receive frequent feedback from operations to ensure thata proper balance is maintained, at the control level, between technical knowledge itselfand the transferability of such knowledge.

2.11 Internal differences due to equipment: A large number of localized technical problemspartly account for the high or even random heat rate values obtained from some units:

(a) in Sousse, substantial air leaks from the air preheaters;

(b) condensers are frequently clogged by algae and marine organisms; as a result, residualpressure in the condensers increases, leading to impaired performance. This problem isparticularly serious in Gabes, where, in addition, the condenser tubes are often blockedby phosphogypsum, a viscous substance discharged by phosphate companies in the ore-washing process; and

(c) the quality of the heavy fuel oil being used has deteriorated (higher specific gravity). Asa result of improvements in the distillation and cracking processes, the oil supplied to thethermal plants has a higher viscosity (the percentage of heavy components has increased);therefore, new and more efficient precombustion fuel heating systems must be installed;consequently, steam consumption by the auxiliary equipment has increased, and heat rateshave risen slightly.

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2.12 Numerous improvements currently underway (particularly to older equipment) shouldreduce the intnal differences due to equipment and thus improve plant performance:

(a) in addition to the extensive repairs in La Goulette described in para. 2.6(c), circuitmodifications and other improvements have been completed or are in progress inGhannouch and La Goulette;

(b) improved fuel preheating in La Goulette enables the use of fuels of international standatd(i.e., with a viscosity between 310 cSt and 380 cSt instead of between 110 cSt and 310cSt), so that savings can be made when the fuel is purchased;

(c) due to improvements to the control assembly, at La Goulette, the boilers can operateusing only small amount of excess air; thus, boiler efficiency is increased, since dry gaslosses have been substandally reduced; and

(d) routine repair of leaks in the demineralized water system (analysis of water samples,checkn for packing leaks) reduces the differences due to water losses.

2.13 In the Ghannouch plant, substantial savings in well water have been achieved by:

(a) use of filtered sea water instead of brackish well water to regenerate the membranes inthe water demineralization system;

(b) use of seawater to ensure the watertightness of the circulation pumps;

(c) use of seawater to clean the main condenser.

2.14 The Technical Service tests the measuring devices at the operators' request. The oxygenmeter readings are checked on site with a simple, portable exhaust gas analyzer, which gives rapid andsufficienty accurate results. The device (similar to the ORSAT) operates on the principle that e variouscomponents of a known sample of gas are absorbed when they are passed through various solutions thathave the appropriate chemical properties. Such tests, made only when operators request them, ensurethe measuring devices in the plnts are reliable.

2.15 To ensure that the measures STEG has undertaken are sustainable, and to refine theresults already achieved, it is recommended that routine tests be carried out on all equipment (at intervalsto be determined). Priority should be given to testing the components that affect the heat rate (checksft leaks, monitoring of pump performance, recording the performance indices of the auxiliary electricand steam equipment, checking fuel combustion, etc.). The results should be entered regularly intologbooks reserved for that purpose, and should be used to anticipate and plan for maintnance operations.

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2.16 UInexlained differences: The high heat rates (and the wide discrepancies among them)recorded for the Ghannouch and Sousse units when these are burning gas are not only due to problemsof unit control or to the condition of the equipment. Inspections performed by the STEG OperationsDirectorate have revealed that, in these plants, measurements of gas flow were highly inaccurate. Gabbs(which uses gas from the El Borma field) has an additional problem with fluctuations in the high heatvalue (HHV). Routine gas chromatography measurements in Gabbs indicate that the composition of theincoming gas varies in relation to the amount of propane extracted from it by the upstream liquefactionfacility; these variations in gas content account for the fluctuations in HHV.

2.17 To make gas flow measurements more reliable, STEG staff plan to install gas gauges atthe high pressure stage (before pressure reduction) in addition to the meters at the Sousse and Radbsplants (done exclusively for large-scale customers). Such measures will not solve the problems relatedto gas metering, which make any heat rate calculation less accurate. Even where dual meters areintalled, it is recommended that the gauges be calibrated by means of standard meters which havecounters that adjust for flow according to variations in pressure, temperature, and density. Before thecalibrations are made, a precision recorder should be used to read gas flow under a constant load and fora reasonably long period (several days). Using this method, abnormal variations in gas flow could beidentified at the same time as heat rates are being computed, over a significant time period.

2.18 To ensure continuous measurement of gas HHV, one solution would be to install anonline gas spectrum analyzer to provide regular readings of mean values at 20-minute intervals. Becausethe equipment is expensive and gas reserves in El Borma are limited, an additional economic feasibilitystudy is needed to determine if such an investment is justified.

Settlng up efficiency monitoring in the STEG plants

2.19 The method STEG uses to calculate the heat rate, which consists of comparing theelectrical energy registered at the terminals of the main transformer with the thermal energy containedin the fuel, provides accounting parameters essential to the management of generating equipment.However, the results do not give a precise indication of the quality of operation of the units, because:

(a) they do not clearly show the impact on heat rate of the various aspects of equipmentmaintenance or of unit management (the internal differences); and

(b) they include items unrelated to plant operation such as differences due to generatingschedule changes imposed by the National Control Center.

2.20 Because STEG recognizes the importance of optimal management of fuel consumption,and its impact on efficiency, it is taking steps to monitor heat rates in the plants. Unit heat rates areincluded in the contracts between STEG headquarters and plant managers, as one of the performancecriteria to be monitored.

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2.21 In addition, efficiency monitoring software is being tested in the plants. This softwareshould enable heat rates to be calculated in conformity with international standards by assessing thevarious components of the units - boilers, turbines, alternators - and evaluating condenser cleanliness.

2.22 Although these measures are important, they do not ensure effective monitoring of thequality of plant operations because they do not provide continuous monitoring of differences betweenactual heat rates and optmum base consumption (OBC). Consequently, the following recommendationsare made:

(a) evaluate the software now under development and estimate the resources that would beneeded to complete it and adapt it to the method of continuous efficiency monitoringsummarized in Annex 5;

(O) evaluate exisfing efficiency monitoring software that could be adapted to STEG's needs;

(c) compare the three possible solutions (internal development of a new system, purchase andadaptation of existing software, or a combination of the two), taking into account thecost, the resources required in each case, time required to implement the system, etc.;

(d) during a first phase, apply the method selected to one 30-MW plant and one 160-MWplant; and

(e) in a second phase, extend the measures to the remaining plants.

Annex 6 contains terms of references outlining the specific tasks to be performed and the technicalassistance required to complete them.

Unavailability rats (1988)

2.23 As defined by UNIPEDE in 1977 (see Annex 7), unavailability rates for STEG plants in1988 are the sum of the following:

(a) unavailability rates resulting from scheduled maintenance work; and

(b) miscellaneous unavailability rates, that is, any factors attributable to plant operaion.

2.24 The unavailability rate is as follows for the various plants visited:

(a) Sousse: Tle mean unavailability rate for the two units was 13.5% in 1988.

(b) Rlh: A steam leak from the HP cylinder seal in unit 1 caused available power to berestricted to 15%-20% from April 1988 until the unit was overhauled the following year.

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(c) Qhawn=gh: Takdng into account only unavailability due to plant operations, in 1988 themean unavailability rate for the two steam units was 18.13%.

(d) La geujtett: The low unavailability rate for unit 1 (13.6% in 1988) is partly due tooverhaul of the unit and to renovation work done in the previous year. Unavailabilityrates for the other units are: Unit 2: 55.5%; Unit 3: 88%; Unit 4: 69%. Thesefigures are high because of prolonged shutdowns of the units for renovation work (similarto that previously performed on unit 1).

Although some individual results are similar to the mean values recorded for similar units in the UnitedStates and Europe over a 5-year period, the lack of statistical data limits the scope for any realcomparison. Commissioning of some units such as Rades 1 and 2 has been performed too recently forthe availability data on these units to be regarded as reliable indicators of the quality of operation. Otherplants have only recently begun to use units that can exchange heat; that situation in addition to thepresentation of operating results in the form of averages makes it difficult or even erroneous to makeassessments of unit performance.

2.25 To improve both the number and the quality of statistics on equipment unavailability, aunified format should be developed for the annual report of activities for all the STEG plants, to facilitatedata analysis and comparison of the results according to unit capacities. It would also be desirable topresent the results by month and by unit in the form of tables and bar charts or graphs, and to avoid theuse of overall averages (heat rates, unavailability rates, unit utlization rates, etc.).

Maintenance

2.26 STEG currently practices routine preventive maintenance in its plants, modified step bystep, in the light of experience (see Annex 8 for definitions of the various types of maintenance). Agroup comprised of representatives of the various units and the Studies Directorate is developing"maitenance" software at the Sousse plant and will supply it to the other plants when it is ready for use.The software complies with STEG's maintenance policy; it is programmed to schedule routinemaintenance, taking into account maintenance done in response to current work orders, as well as theoperating record of the equipment, so that the time periods between routine maintenance interventionscan be modified accordingly.

2.27 Routine maintenance also depends on. continuous monitoring of significant parameters orof operating parameters that reflect changes in the performance or degree of wear of a component, asfollows:

(a) vibration readings on the main turbogenerators, in compliance with manufacturers'standards (using portable or fixed equipment);

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(b) analysis of oil samples (turbines, diesel engines) since this often indicates the conditionof the interior parts; and

(c) vibration analysis (of the steam and gas turbine blades) by the Technical FacilitiesDepartment (DPITG) to detect cracks.

This type of maintenance, 'modulated' by the equipment operating record and by permanent monitoringof the equipment while it ;s in service or during scheduled shutdowns, is increasingly pricced indeveloped countries, particularly in the United States, where it is referred to as "conditional or predictivemaintenance."

2.28 The maintenance procedures developed by pov. r utilities depend on the type of equipmentbeing used, taking the safety of personnel and the impact of unavailability on overall service quality intoconsideration. International experience has shown that conditional maintenance is advantageous forgeneratig equipment, particularly for high-powered units; for example, In develope countries -particularly in the United States - conditional maintenance has reduced maintenance costs for somecomponents (such as feedwater flow controls) of 300 MW and 500 MW nuclear and thermal power unitsto about 30% of their previous level.

2.29 For Tunisia, it is recommended that a small task force be established at the centralmanagement level, responsible for developing maintenance guidelines specific to STEG equipment andadapting maintenance procedures to match these guidelines, so as to improve equipment availability andreduce overall maintenance costs.

2.30 Considering that units with increasingly high power levels are being introduced, thefollowing measures should be taken to develop conditional maintenance for the generating oquipment:

(a) increased - and more routinized - vibration recordings of the turbogenerators, at leastfor the most recent equipment, that used in 150 MW or larger systems), and adoption ofroutine inspection procedures (analysis of oils, monitoring of insulator status), needed toimprove monitoring of the pattern of change in the varicus components; and

(b) more efficient use of DPITG's technical and human resources by introducing routine gasturbine inspection procedures (ultrasound, thermography).

2.31 The introduction of conditional maintenance procedures complements the establishmentof plant efficiency monitoring; financial resources dedicated to monitoring equipment components willserve both objectives. Routine monitoring of some components could later be incorporated into moreadvanced computerized systems (expert systems) that could be used tQ4,determine the type of work to beperformed during equipment shutdowns so that routine maintenance on components that do not requireit could be avoided.

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2.32 Inventory management software is being developed for the plants. Tbis conventionalinventory management model has the following features:

(a) cataloguing and categorization of equipment;

(b) (automatic) request for replenishment of items once they fall below a predetermined level;and

(c) adjustment of this level to match acwal inventory turnover.

This software is being tested at Sousse and will soon be supplied to the other plants.

2 31 Inventory levels in STEG's plants are higher than those maintained in power utilites indeveloped countries because the observed average time lapse between order and delivery is, in somecases, as long as two years. This excessively long delay has the following consequences:

(a) large numbers of staff are required to follow up on orders, analyze the bids, and issuenew requests for bids in cases of nondelivery; and

(b) subsi funds are tied up in 'precautionary" purchases of items to be kept in reserveto guard against the risk that a unit's unavailability will be extended when it isoverhauled, due to a lack of spare parts (lack of inventory).

2.34 Although some operations are either unavoidable or cannot be performed in less than thedme allotted, an in-depth analysis should be made of the various stages of the spare parts procurementprocess, from the decision to obtain supplies to the delivery of equipment at the storage facility, toidentify the causes of delays. The analysis should lead to:

(a) intenally, elimination of superfluous operations, changes in certain management rules,and/or possible changes in signature requirements; and

(b) extrnally, preparation of document to be discussed with government authorities, witha view to reducing the length of time needed for importing goods; the documents wouldenmmerate the benefits to be expected from simplification of Import procedures.

2.35 For the procurement of consumables (for the cental warehouse), the utility should furtherstanrdize supplies in order fp simplify acquisition procedures, without jeopardizing the utility's abilityto encourage competition between the various suppliers in order to obtain the most advantageous financialconditions.

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(:ambustion Turbines

Heat

2.36 Desiga considerations (exhaust gas temperature) restrict the perfomance of thecombustion turbines. The observed decrease in the performance of the turbines In service Is mainly dueto dirt blocking the air prefUiters and filters. The uilt control operators constantly monitor perbrmance.Filters are regularly dhanged and the compressor blades are cleaned either manually or by the use ofcarboplast. Average heat rates are classified by Ite and by year (see Table 2.3); this practice Illustratesthe need for more detailed investigation to discover the reason for these differences and to use the resultsto implement a program for reducing fiuel consumption. For example, a 1% reduction in heat ra in1989 could have produced fuel savings of about 15 million thermies or 1500 toe.

2.37 Because of their marginal use, combustion turbines are installed ad hoc in locations wherepower generaon is insufficient. They are often used in spite of their high heat rates,2/ because theycan be insWlled rapidly and require a lower capital investment than steam thermal units. Because theselow-capacity units are widely dispersed, maintenance resources are also dispersed; thus, It is difficult toplan overaill gas turbine maintena, manage inventory, and take prompt maitenance actions whennecessy. STEG's combustion turbine maintenance resources are inadequate:

(a) a general storage facility at La Goulette 1 (on the site of the former plant);

(b) a maitnance office in the Operations Directorate; and

(c) on-site team to provide unit control and preventive maintenance.

STEG does not have enough personnel to ensure adequate maintenance of the gas turbines, and theprofessional experience of existing personnel is insufficient (of the 15 members of the maienance staff,10 have less tma two years' experience).

ai The sue4y progressmade in Ireasingdte reiabiry of cmbustx twubiesmd bipro*Ig their heat rae, d theadanagesa of bnwpora*8 a en cycle, hould be notd

Tabl 2.3: SMEG - STATISTICS FOR THE COMBUSTION TURBINES 1988-1990

lt Puiss. 18-s 1969 - - 1990 C_ut des N. CAt deaN.Caoatd.l -NW__ de awch fin do dimrag

________ _ _ _ tI ID CS 10 fibO0 t -D CS ID FiabD -W DI CS ' TO FibO D aot 19 fin coOt 19

Gha.maudl t 1S J3 IW 33 S1 l 755 39 3311 65.2 31.5 104.1 23 4311 75.7 33,6 827316 2 22 494 38 3450 10. 94, 3200.7 2__ 3_S n,7 36.7 16383 134 3550 ,Sa 92.2 74547.6 , - i_ _ s

1 22 4758 17 3565 94 9 *9 4642.3 165 3481 972 ff, 7 3702 2 3753 434 95f3 90324.9 3135

4 4 MA _ . . 3c9.t 22 3754 9 100 2360,6 123 3740 99.71 93 = 20280.8 S70

I 31 4118 54 3913 76. 981 130 26 373S 19.3 88 1 1808-1 37 3797 94.61 100 6787'? S 8418auceaChu - -&

2 31 4016.8 75 3861 9*, A' 4*780 34 3915 93 4 100 39,.1 4 3707 100 100 6301%2 983

1 22 261.3 50 44S 6. 98 7 390S5 1Sl 3850 96.9 93.3 363L2 108 8N 99 100l 26196.7 5803

TInis Wud 2 22: *132 IS4 383 6 ".a 329. 133 4511s stt s 3 130 3t58 9.1 a 9 100I 3575

-_______ _ ._ 22 623.1 1 4 3635 s 97.7 597.3 1SS 375S4 ". s.r 253 89 364S 83 9 23635 3474

1 22 .. 9.. 1731 3527 93.6 9,.4 1661 !"I 9233 92,3 s 902 161 3485 94.9 35. 19693.8 18ts

2 334 1f3s9 229 3SSO 3.3 ff 6 1934j 8 322 3328 94.2 ss,s 156S.7 226 3? 94.9 90.2 1j57r2 1310

1XZ t 34 1260 19 3705 M 3 s,5 1110,9 203 3m 97 913 I 1278,7 204 343 137 8s8 121703 1436Kasserta. - - - *~~~~~~~~~~~~~~~~~~~~~~~~~~~~ *a- -~~~~~~~~~ -- M ass 110313

2 34 141? 210 3450 n.y1 .SC 1f05,7 221 3572 96,3 96.51 1 217S 203 3509 99.3 949 1123s.a It

P. Bout4iba 1 22 22.3 22 4531 3.s S6.4 29.3 33 463? 8 s.91 tJ 9 4 042 n5 ss4 12,5 2173

R 22 S 5. 3 4740 67.8 67.3 41 52 4389 9.6 100 *3-1 1.4 '4127 63.2 1OO 12254-3 2001

1 22 55 68 4970 70.4 n . s 33 21 3889 9r f f.2 Z 1t9 3875 " .9 F 402 1480

2 22 76 57 468 78,9 79 32e8 24 4 797 85,3 19.6 12 4041t -99 , t ff 6782,9 1990

net 2mal 1 22 49.2 28 488 99,7 tO 2.5 1?7 433 j , too Si 13 40 %.4 tO1 5634,5 12S4

RobbUt I t 35 175.8 50 S231 9S 100 83, 26 4W3 9,4 92.3 37.2 22 4223 97 682 1700 49

HM: Houts of Opetation; ND: Number of Statups; CS: Heat Rate (kcal/kwh)TD: AvaBabiit Rate (%); Fiab. D: Statp Reiability (%)

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2.38 To facilitate maintenance and planning operations for all combustion turbine installations,we recommend that STEG establish a "Procedures Department" (Bureau des Methodes - BDM), whichwould have the same responsibilities as the existing BDM for the steam thermal plants. Tbis unit couldbe located close to the general storage facility at La Goulette so that it could perhaps benefit from supportfrom the DPTG (in the form of laboratories and workshops). It should be provided with a drafting officeand should have a documents manager who would be responsible for putting together a complete set oftechnical information on the various units. The set would include flowsheets, repair charts, the operatingrecords of the machines, and information on the range of maintenance actions to be taken.

2.39 With regard to training, the consultant proposes that staff members who have attendedshort training courses abroad (organized by the manufactrers) should organize seminars, possibly withassistance from the Khledia training center, to pass on their knowledge to others.

Unavailabiltv

2.40 If more resources are provided for maintenance and training, equipment availability andstart-up reliability should be improved. The equipment start-up average (about 88% in 1988 and 1989)is too low. (Under normal conditions, the average should be between 95% and 100%.)

Hydropower Generation

2.41 The hydroelectric instatlations in the west of Tunisia are used mainly to:

(a) regulate water flow from the wadis when water levels are high;

(b) irrigate farmland; and

(c) provide drinking water for the large towns.

The remahing capacity is used to power turbines following an hourly quota managed in cooperation withthe National Control Center. (Mhe water is used mainly during peak hours, to avoid sturting up moreexpensive equipment, such as gas tirbines.)

l!fflciency/WAvalb ty

2.42 The performance of foot-of-the-dam hydropower installations that receive highysedimented water is generally poor. In such cases, turbine blades suffer wear (as at Nebeur) and the

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turbines have to be remetalled. This technical problem is under control in the STEG installations, andthere is no real problem of unavailability.

2.43 Equipment scarcity and equipment aging are the main causes of maintenance problems.Consequently, operators have considerable autonomy in performing maintenance. The equipmentoperators handle routine maintenance, while teams that include personnel from other plants perform majormaintenance and overhauls, with support from DPTG when necessary.

Conclusions and Recommedations

2.44 The audit of STEG's generating operations confirmed that the utility performs thesefumctions well, despite some shortcomings. Improved procedures for equipment management andoperation and improvements in the operators' technical knowledge would help overcome theseshortcomings, consolidate the considerable progress achieved over recent years, and increase theefficiency of existing and future generating resources, bearing in mind that STEG is still facing a rapidtempo of investment.

2.45 STEG is aware of the need to increase the efficiency of its system and has taken a numberof steps in recent years to:

(a) reduce fuel consumption in the plants by: (i) overhauling and modifying the systems inits aging units, particularly in the Ghannouch and La Goulette plants; (ii) developing asoftware application to improve monitoring of fuel consumption in the steam plants.STEG's experience confirms the conclusions reached by ESMAP in several countries,that investment in renovation produces high economic returns. In Gabas, modificationsand improvements to systems by the plant's maintenance personnel have produced savingsof about TID 105,000 (about US$117,000) per year through reductions in water losses,and the investments made in improving regulation and in installing fuel heaters at LaGouette 2 were recovered in nine months through the energy savings obtained; and

(b) improve management and equipment operation by modifying procedures and developingcomputerized systems that enabled better maintenmce in the steam plants (through a pilotproject at the Sousse plant) and better inventory management by the plants.

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Shortem recommendation

2.46 The following measutes are recommended:

(a) continue to renovate those aging thermal steam generating plants whose renovation hasbeen proven cost-effective in STEG studies, which, incidentally, considered only thesavings to be made from reduced water loss (Gabbs) and reduced fuel consumption (LaGoulette). In addition to these benefits, renovation extends the usefil life of equipmentand defers the need to invest in new generating equipment;

(b) evaluate the "fuel efficiency monitoring" and "maintenance' software being used in thesteam thermal plants to ascertain whether it can be adapted to more advancedmanagement methods such as online efficiency monitoring based on the continuousmonitoring of deviations from optimum base fuel consumption togedter with 'condidonalpredictive maintenance' based on continuous monitoring of the units while they are inoperation; and

(c) improve the availability and quality of the data needed for introducing more advancedmanagement and operating procedures in the plants. This measure could be incorporatedinto a thorough review of STEG's data gathering and processing system, but somemeasures, such as improved gas metering at the Ghannouch and Sousse plants, areurgently needed.

MediUMe recommendaio

2.47 Continuation and consolidation of its existing activities will enable STEG to upgrade thequality of its management and adopt the most advanced methods for operating its generating units andmonitoring their performance.

2.48 Q:anLional measurss: To improve coordination and prepare for implementation ofmore efficient maintenance procedures, three minor structural changes in the Operations Directorate arerecommended:

(a) create the position of manager for steam turbine generation with the same level ofresponsibility as for existing positions related to gas turbine generation, hydropowergeneration, and transmission. Providing an intermediary between the plant managers andthe Operations Director would ensure (i) separation between the management andoperation functions; (ii) individual representation of steam generation in the OperationsDirectorate, similar to that for the other generation functions; and (iii) reinforcement ofthe Operations Director's coordination role;

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(b) create a "Procedures Department" (Bureau des WMthodes - BDM) to enhance andcoordinate maintenance and operation of the combustion turbines. Tbis department,which should play the same role as the existing BDM for the steam thermal plants, couldbe located at La Goulette so as to benefit fror# the assistance of the DPTG; and

(c) create a small unit (consisting initially of one engineer and one technician), to beresponsible for developing maintenance procedures and programs and updating them inline with equipment operating records supported by operating reports from the generatingplants and by the results of inspections and monitoring of equipment in operation.

2.49 Individualized training for steam turbine operators: It is recommended that STEG developan individualized training strategy for the operations shift teams, by preparing a set of training packagesbased on operating documents (procedures, instructions, etc.). The advantage of this strategy is thatspecialized staff can receive well-synchronized training and advanced training despite the problemsconnected with shift rotation.

2.50 Installatio of on-line steam turbine efficiency monitoring: The mission recommendsinstallation of an efficiency monitoring system for the steam turbines, based on continuous computerizedmonitoring of performance parameters and their comparison with unit reference parameters, to ensurethat actual fuel consumption approximates optimum base consumption as closely as possible.

2.51 According to the consultant's estimates (confirmed by previous ESMAP studies) the costof preparing and implementing the project would be about US$1 million. If implemented, the benefitswould be about US$1.1 million in 1991, based on the following very moderate assumptions:

(a) a 1% gain in heat rate for STEG's steam thermal equipment, or 2.6 toe/GWh on thebasis of 1988 operating conditions; and

0b) a toe/fuel oil cost at the 1988-89 level of US$100/toe.

The payback period, about 11 months uder the conditions assumed by ESMAP, indicatesthe definite benefits of the project. STEG should define and prepare the project in more detail followingthe terms of reference provided in Annex 6.

2.52 plfnnaion of conditional fpredictive) mainteance Vroam: It is recommended thatSTEG implement conditional, predictive maintence programs (being used increasingly in the developedcountries) for each equipment component or group of components, based on updated operating recordsand on development of local and centalized inspection and monitoring (in DPTG). Such a programwould provide improved data on component aging and would considerably reduce maintenance costs bydecreasing routine maintenance. ITe financial benefits of the program are difficult to estimate, as STEGdoes not itemize maintenance costs for accounting purposes. A reliable estimate of the savings to beexpected from such a project would require a very detailed financial and technical study of STEG's

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maintenance program, which is beyond the scope of the present study. However, ESMAP's experiencein this area indicates that such projects have very high internal rates of return (about 45% in the case ofSyria: complete reorganization of the maintenance management system). By way of illustation, Tunisia'sestimated maintenance costs for thermal equipment were TD 11.25 million, or US$12.5 million, in 1989,and are likely to be between TD 13.5 and TID 14.5 million (between US$15 million and US$16 million)in 1995, based on a standard cost, observed in a number of developed countries, of US$10 per kW. Itfollows that a mere 10% saving on maintenance costs would reduce STEG's operating epenses byUS$1.25 million in 1990 and US$1.5 million in 1995.

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m. TRANSMISSION

3.1 bI 1989 the STEG network comprised:

(a) 2,852 km of lines divided between three voltage levels: 920 km at 220 kV, 1,256 kmaat 150 kV and 676 an at 90 kV; and

(b) 41 transformer substations, with a total insaled power of 3,805 MVA for 92transformers of sizes ranging from 15 MVA to 200 MVA.

The map at the end of this report provides a simplified diagram of the network.

Simnulation of Transmission Network ();raions

3.2 An in-depth study of selected operating situations on the transmission network (selectedin close coopeation with Tunisian counterprs) was carried out in three phases:

(a) collection and preparation of the data needed to create a representation of the networkcompatible with the computer model used;

(b) simulaton of network operations and deermination of losses in accordance with theoperating samples selected (differentiated according to consumption level, availablepower, degree of compensation, and voltage level); and

(c) loss anlysis, and a search for solutions appropriate to the problems identified.

The data used in the study, related to the present and projected network, are given in Annex 9.

3.3 Studies of network operation under several operating scenarios were made for the years0989 and 1993, using the following parameters:

(a) md: Three demand scenarios were used: (i) maximum, or evening, peak, exceededfor only one or two hours in the year under study: 700 MW in 1989 and 1000 MW in1993; (i) average, or morning, peak, exceeded for about 1000 hours in the year understudy: 646 MW in 1989 and 829 MW in 1993; and (iii) off-peak, or night, period,exceeded for about 7600 hours in the year under study: 420 MW in 1989 and 542 MWin 1993;

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(b) oleag loek: The minimum acceptable voltage on the 225 kV network is 200 kV. Forthe maximum voltage, three values were used: 210, 225, and 235 kV, to enable anassessment of the sensitivity of reactive energy compensation and of power losses to thevoltage level;

(c) 1989 cpnsation stas: Three compension situations were considered for 1989(situation at the time the study was made): (i) a total absence of compesaUdion; (iicompensation using only existing resources; and (ui) additional compensation obtnedby installing new equipment to obtain an overall tan phi of 0.5 as viewed from the RVnetwork;

(d) 1923 compesi status: Two compensation situations were considered for 1993: (i)a total absence of compensation; and (i) compensation needed to obtain an overal tanphi of 0.5, as viewed from the RV network.

Tan phi was se at 0.5 as this is the value at which the network can operate satisfactorily;It avoids large transmissions of reactve power and guarantees a large margin of securityagainst voltage collapses; and

(a) =aft pgM sta Three scenarios for power generation andlor exchanges of powerwith Algeria were examined: (i) imports from Algeria without compensation; (Ii) a supplyof up to 250 MW from a thermal plant at Cap Bon; (iii) installation of gas turbines toproduce an additional 200 MW (see Annex 9, page 4). The latter two cases wereexamined with and without additional compensation in 1993.

There is little or no likelihood that power will be supplied in 1993 from a plant in Cap Bon, but thishypothetical case, studied at STEG's request, is useful to understanding the longer-term problems facingnetwork operations If this plant is brought into service.

3.4 The simulations of transmission operations, the results of which are given in Annex 9,leads to two major conclusions:

(a) theoretical energy losses in 1989 total between 0.9% and 1.3% under the operaigcondidons studied; they represent only about one third of actal identified losses, whichwere about 3.6%. In the medium term, these losses should not increase under any of theconditions studied provided that STEG adopts measures for improving tan phi tiroughincreased compenston. The sensitivity study shows that these losses vary as follows:0) for the morning peak in 1989, total losses are about 7 MW, the sensitivity of lossesto compensation is about 0.2%, i.e., 1.6 MW for 170 Mvar of compensation; and (ii)for the morning peak in 1993, total losses vary from 6 MW to 18 MW depending on thegeneration hypothesis considered; the sensitivity of losses to compemation is about0.15%, i.e., 1.2 MW for 218 Mvar of compensaion; and

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(b) the values for tan phi are abnormally high during the day, particularly at the morningpeak, about 0.7% in 1989 for the cases studied. There are no prospects for improvementin the medium term and there will even be some deterioration unless steps are taken toimprove compensation. By 1993, 211 Mvar (i.e., 171 Mvar more than the present 40Mvar) will be needed to maintain tan phi at its overall 1989 level, whatever generationhypothesis is used.

Actions Needed to Reduce Losses

3.5 It is difficult to draw distinctions between direct and indirect causes of technical lossesin transmission networks, as electrical phenomena are complex and interactive. Nevertheless, the studyfindings, the results of additional work undertaken, and the outcome of discussions with STEGtransmission network managers and operators favor three types of action, that would ensure:

(a) improved system control, through optimization of flows to maintain a high voltage level,thereby guaranteeing a secure supply, and a sound management of compensation capacity;

(b) improved operation and maintenance of the transmission network, with particulartntion to managing the transformgrs, maintaining the transmission network in good

condition, and maintaining the equipment; and

(c) progressive actions that contribute indirectly to increasing the efficiency of thetransmission network: additional resources for planning and network studies,organizational changes, and training for operations and maintenance personnel.

STEG Network Control

3.6 The network control system STEG has implemented is satisfactory and enables collectionof the data needed for making real-time responses to any incident or contingency. Nevertheless, thesimulation of network operations has shown that network efficiency could be significantly improved bymeans of improved system control and investments in compensation.

YQV a level

3.7 For voltage levels of 150 kV and under, the transformer on-line tap changers ensure thatthe proper operating voltage is supplied, provided that the transformers do not reach their operatinglimits. However, the 225 kV level that STEG us as its primary operating voltage level is too low and,as a result, the voltage level drops off when outages or difficult operating conditions occur.

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3.8 Toe simulations of network operations indicated that raising the maximum operatingvoltage level from 210 kV to 225 kV reduces active power losses by about 2 MW for a load of 1000 MW(the maximum demand forecast for 1993); this reduction, valued at the incremental cost of the cost oflkW of HV power (see Annex 2) gives a financial saving of about TD 400,000, or US$444,000.

3.9 When overall voltage levels are increased, service quality improves, and the risks ofunplanned load shedding due to voltage drops and to engine re-start failures, are reduced. Statistically,a 5% drop in nominal voltage produces a 2% drop in peak load. Thus, low supply voltages, in additionto being detrimental to consumers, also cause financial losses to the utility.

3.10 It is therefore recommended that STEG:

(a) study and determine performance criteria for network operation, such as a minimum ofvoltage levels and possible deviations from those norms (operational planning).Establishing such criteria will enable STEG to: (i) identify weak points in the network,especially if changes may have been made in operating guidelines or if there have beenlosses of reactive energy generation capacity; (ii) determine the reactive power capacityavailable from connected generating units, on the basis of manufacturers' chartsindicating their ability to supply reactive power at the alternator terminals; and (iii)anticipate the onset of a voltage collapse so that timely measures (such as: connectingcapacitors, disconnecting reactors, increasing the demand for reactive power from thealternators, blocking tap-changers on the VHV/HV transformers, and load shedding) canbe taken to raise voltage; and

(b) update its manual procedures for secondary voltage regulation. Even if automaticsecondary voltage regulation theoretically improves the quality of voltage regulation andallows coordination of the alternator outputs, it is much better to maintain voltage levelsby reactive power compensation. Substantial loss reduction will also be realized byreactive compensation.

Comepeation

3.11 To ensure acceptable service quality and satisfy demand at least cost, i.e., by limitingvoltage drops and reducing active energy losses, one must have sufficient compensation capacity (reactorsand capacitors) and operate it correctly so that the production and consumption of reactive power can besuitably controlled. Simulations of network operations, and discussions with the operators, during themain mission, showed that STEG can make much progress by: (i) providing compensation by operatingthe existing reactors more efficiently; (ii) possibly using gas turbines as synchronous compensators; (ii)properly managing the step-up transformer taps on the generating units; and (iv) installing additionalcapacitors.

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3.12 Oeation of thg m gret: STEG's method of operation of its reactors does not alwaysenable it to maintain continuous control over the generation and consumption of reactive energy and,subsequently, to maintain a high enough voltage level to provide adequate service quality and minimizelosses. For example, all reactors are disconnected manually between 7:00 a.m. and l1:00 p.m. (16 hoursa day), except for the 6-Mvar reactor at the Ghannouch substation (Robbana feeder) which is notequipped with a breaker. This means that during the morning peak when there is a shortage of reactiveenergy (see Annex 10), the additional 6 Mvar of demand causes additional losses. Annex 12 shows,however .bat loss reduction alone is insufficient economic justification for installing a breaker.

3.13 Use gf the Tunis South gas turbine a synchronous-cgmpensatrs: Should difficultiesin maintaining voltage level arise that jeopardize network reliability, one solution would be to use the gasturbines in the Tunis South plant as synchronous compensators, providing a margin of security of 3 x 20Mvar. The results given in Annex 10 show that the power loss reduction obtained is less than the gasturbine consumption (0.8 MW). The only justification for using this equipment, therefore, is to resolvelocal constraints connected with maintaining voltage levels.

3.14 Manament of step-up transformer taps on the generating units: Current managementof these taps is inefficient, because taps have to be selected before the transformers are energized. Thispractice sometimes leads to unbalanced taps on the same site, with no possibility for the Service desMouvements d'Energie (SME) to intervene. Because taps can only be set when the units are tripped, itis recommended that the SME be made responsible for managing taps and that it develop a seasonalmanagement procedure that would allow savings in reactive energy, and would contribute to improvingthe voltage level at almost no cost (labor costs, about twice a year). STEG's operations forecast for 1989indicated that a preliminary study of such procedures had been made, but no subsequent action was taken.A complementary study should be made on the autotransformer taps, which are also set manually.

3.15 Installation of supplementary capacitors: A convenient measure of reactive level is theratio of the reactive power to the active power. This ratio is given by the tangent of the power factorangle and is termed "tan phi" hereafter. The simulation of transmission network operations showed that,in 1989, an additional 130 Mvar would have been necessary (124 Mvar if the Ghannouch reactor hadbeen fitted with a breaker) to reduce the overall tan phi from 0.7 (the value recorded at that time) to 0.5,the value usually regarded in similar networks as being the upper limit needed to ensure a reasonable losslevel. In the medium term, 211 Mvar will be needed by 1993 in order to maintain the overall tan phiat O.5.

3.16 A more detailed study was made for substations with a reactive to active power ratioexceeding 0.6 (for the year 1989). The compensation requirements at these substations to reduce theration to 0.5 were also determined. The results of the study are given in the tables and network diagramsprovided in Annex 10.

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3.17 Examination of the results obtained, particularly in the sensitivity studies, shows that thereduction of losses obtainable on the transmission network by means of reactive power compensationwould not be sufficient to justify installation of compensation equipment on the VHV and HV networks(see Annex 12). On the other hand, compensation plays a useful role in maintaining a high voltage levelunder both normal and abnormal conditions, thereby considerably improving operating reliability.Furthermore, installing compensation as close as possible to the load, i.e., close to HV customers thathave a high reactive load (cement works), or in MV substations, can be justified by means of specificstudies carried out on a case-by-ase basis. It is recommended that STEG, before making any decisionson investment, increase its tariff incentives to encourage its customers to make their own investment incompensation equipment.

3.18 Taking equipment out of service in off-peak hours. Taking equipment, particularlytransmission lines, out of service during off-peak hours ensures better control of the voltage level. It alsoprovides the generating units with a wider operating margin for possible exchange of reactive power. Tobe effective, these measures must not compromise network reliability under normal conditions or undercontingency conditions (tripping of one line or one unit). Taking VHV/HV or HV/MV transformers outof service may reduce the losses caused by these transformers at low load (by eliminating the core lossesof the transformers that are removed). The transformers should only be taken out of service whileobserving the n-i rule (the "n-I" rule is respected if tripping of one line or unit enables the load to besupplied without overload or any unacceptably low frequency or voltage). The equipment must bereturned to service quickly when required by an increase in load or to restore the n-i condition.

Operation

3.19 STEG's operation of its transmission network is satisfactory on the whole, but additionalmeasures should be taken to improve management of the VHV/HV transformers, improve the mechanicaltension on some lines, reduce the effects of pollution on the insulators, and improve inventory control.

3.20 Manaent of the VHVM V trasformers. Some of the equipment appears to beoversized in relation to the load transmitted. The low load levels observed on some occasions should leadthe dispatchers to undertake more rigorous management, such as

(a) taking some transformers out of service; and

(b) avoiding circulating currents of reactive power by Installing automatic devices when unitsare operating in parallel.

Despite existing constraints, such as the ring-bus in the design of most of the transmission stations, andthe operational practices for the distribution system, it appears that new operating guidelines can beestablished after an appropriate study. Also, transformer procurement practice should take into accunt

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losses over the desired lifetime of the equipment. The discounted cost of the losses are to be added tothe investment cost for the transformer.

3.21 Mechanical tension on some lines: Some lines have a high degree of sag and the effectsof creep are particularly noticeable on the 150 kV network. The mission recommends that STEG makefield measures of cable sag to obtain the data required for a technical and economic study of the need tore-tension some cables.

3.22 Effects of pollution on the insulators: In some areas where the network is affected bypollution from chemicals and algae, and by sandstorms, STEG sometimes has to reduce the network'soperating voltage. In addition to manual cleaning and silicone treatment of the insulators, two procedurescurrently in use in Tunisia, it is recommended, wherever water is available, that STEG study thefeasibility of spraying the insulators with water, as this can be done without interrupting the voltagesupply to the system. STEG is also interested in current research on specific insulator types (such as theaerofoll design) suitable for areas where the rainfall is too low to clean the insulators without humanintervention, and has set up a committee to study pollution problems as well as the feasibility of instaligGas Insulated Stations (GIS) in certain regions.

3.23 MA : The Operations Directorate is currendy reorganizing work procedures andmaintemnce. The reorganization, based on decentralization, creation of regional storage facilities, andcomputerized inventory control, should improve the maintenance of the transmission network and thusimprove equipment availability. It is recommended that STEG complete this program, placing geremphasis on:

(a) decentralization, except for equipment that is very expensive, or is sensitive to climatechanges. An air-conditioned storage facility will be maintained in Tunis. It should benoted that the current inventory control system is too centralized, and there is nojustification for centralization of some equipment, relay protective devices, for example;

(b) staff expertise and quality; and

(c) development of a system of data exchange between the storage facilities and networkingof computerized management systems.

Additional Actions Needed to Improve the Efficiency of the Transmission Network

3.24 In addition to the measures recommended previously to improve unit control andoperation, actions needed to enhance the overall efficiency of the transmission network i<clude minororganizational changes, improved network planning methods, improved and increased personnel training,and Increased coordination with the other Maghreb countries in order to improve the efficiency of use

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of the interconnection through creation of a coordination and control center for the Maghreblaninterconnection.

3.25 Q gaijQn: Two minor organizational changes are recommended so that theresponsibilities for operations and customer management will more closely match the technicaldemarcation between transmission and distribution:

(a) division of responsibility for setting up and managing the relay protective devices alongthe same lines as the functional demarcation between networks, because: (i) tramsmissionand distribution operating policies and procedures are different; (ii) assigning theresponsibility for the policy of protecting its network relays to the DistributionDirectorate (DD) should improve its ability to manage and coordinate network operations;

(b) creation of a unit within the Operations Directorate to take over the mmagement of HVcustomers, currently the responsibility of the DD. Creation of this unit should lead toagreements between the OD and its major technical and commercial customers. This unitwould be responsible for the billing and management of HV customer contracts, includingthose with the distribution centers, which would be considered to be HV customers. Thischange would create a climate favorable to: (i) increased authority for managers in eachcenter; (ii) greater transparency in their relationships; and (iii) greater incentives toefficiency.

3.26 Planng: Existing network studies are based only on projected annual peaks. The scopeof the studies is insufficient, because major operating problems can arise at other times. Planning studies,particularly the fvaluation of network losses, require study of network operations according to severatldemand scenarios (seasonal, daily, or even hourly). For example, the network simulations performedhave shown that excess reactive energy demand is more cause for concern during the morning peak thandoing the evening peak. Consequently, improvements to the Planning Directorate's data processingresources are recommended, to enable it to manage the increased workload required for making the kindof network studies needed to improve medium- and long-term planning. Predictive planning models areavailable that are well-suited to these kinds of problem and enable a network development master planto be prepared, to be used as a decisionmaking guide for the short term.

3.27 It is therefore recommended that:

(a) STEG's economic unit prepare and implement standard economic appraisal techniquesfor investment projects and/or development options; among other things, STEG sbouldinclude in its economic appraisals a cost of unsupplied energy, defining the effort it isprepared to make to improve service quality; and

(b) that the data processing unit routinize and computerize its data gathering and statisicalwork, to increase the progress STEG bas already made in this area.

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iLai

3.28 STEG is currently making considerable efforts to train and upgrade the technical skillsof Its personnel. Most training is transmitted informally on the job from one operator to another, amethod which, contrary to the conventional wisdom, has been shown by experience to be the mostexpensive and unsatisfictory form of training. It leads to widely varying levels of knowledge among theoperators, because workers are qualified without objective and consistent evaluation of their skills at thecorporate level.

3.29 More precise and targeted training is recommended, to be achieved by investigating andimplementing a training plan that provides more homogeneous training for staff, taking into account theircareer development and the utility's needs for qualified personnel. For technical and techno-economictraining, it would be preferable to designate several trainers from the operating units. These designatedtainers would then t4eive additional technical training and instruction in teaching methods, outsideTunisia, in power or gas utilites, or with the equipment manufacturers. Upon their return, they will beexpected to develop training programs that fit STEG's needs and to disseminate the information.

3.30 Tye of training needed. Operator qualification is currendy based on job descriptionsand on seniority. This situation can be improved, and incorrect equipment operation and its consequencescan be reduced, by means of short training courses at the Khledia Vocational Training Center (Centrede Formation Professionnelle de Khledia). With adequate training materials and competent Instructors,the operators could receive their operator's qualification following national tests that would be uniformlyestablished.

Interconnection

3.31 lIvestigation of the operation of the Maghrebian interconnection is beyond the scope ofthis study. However, it should be noted that the network interconnection between the three Maghrebiancountries (currently Tunisia, Algeria and Morocco, to be joined later by Libya and possibly Mauritania)is not used optimally, mainly because tariffs for the exchanges are not based on economic costs andbecause there is no coordination or ongoing data exchange between the three currendy interconnectednetworks.

3.32 Creation of a coordination and control center - serving as a locus for pooling informationand data, but with no opeational autority over the control of each country's own networks - couldmake for more efficient use of tle interconnection, but, more particularly, it could serve to centralizetechnical information and disseminate it rapidly. For example, an analysis of past technical incidents,pardtcuarly the one that ocurred on January 17 1990, shows that the values of primary and secondaryreserves are too low and this often leads to under-frequency load shedding (shedding through frequencyrelays). The proposed 'control center" could deal with this problem as follows:

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(a) establih an indicator for monitoring the primary control of the Maghreblan system. Attimes of significant disturbance, the frequency varlation would oe analyzed and eahpartner would be provided with an estimate of the static gain of the primary control (inMW/Hz) of the interconnected network. The indicator, used comparatively, would givean assessment of the degree to which the primary reserve has been drawn upon, at leastfor the frequency variations noted; and

(b) coordinate and optimize in real time the value of the secondary control, since (bydefinition) this is distributed among all the countries in the system. Exchanges oftelemetered data between the countries would enable country operators to optimize thecorresponding networks in their network load flow calculation models.

3.33 Clearly, there are costs involved in participating in the primary and secondary controlsystems, as In the above examle, and for the other operating measures that would be needed. Tbesecosts must be determined and allocated optimally among the various networks so as to minimize the costsof supplying power. It is therefore recommended that COMELEC (Comite Maghrdbin d'Electriclt6)stdy the feasibility and cost-effectiveness of establishing a Maghrebian coordination and control center,basing its study on previous international cooperation experiences in power interconnections, such asthose of NORDEL (Nord Electricit6) and UCPTE (Union de Coordination des Producteurs etTransporteurs de l'Electricit6).

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IV. DISTIBUTION

4.1 The STEG distribution network operates on four voltage levels: 30, 15, and 10 kV inthe medium voltage (MV) range and 400/230 V in the low voltage (IN) range.

4.2 The MV network is radial and comprises:

(a) 13,000 km of 30-kV overhead three-phase lines and 4,000 km of single-phase lines at17.3 kV. The neutral of the three-phase overhead network is distributed and grounded;it is therefore a l4-wire' system;

(b) 1,000 km of 10-kV lines, mostly underground, supplying cities in the north like Tunisand Bizerte; and

(c) 354 km of 15-kV lines, supplying large towns in the south like Gabbs and Gafsa.

4.3 Ibrough 17,000 MVILV transforming substations (including 6,700 customer substations),this MV network supplies a 30,600-km LV network, 97% of which is overhead. Following a major driveto change voltage. almost al MV/LV subsations (98%) now operate at a secondary voltage of 400 V,while the remainder (2%), more than two thirds of which are concentrated in the Tunis region, operateat a secondary voltage of 230 V. Annex 13 provides a detailed description of the STEG distributionnetwork.

4.4 Given the extent and diversity of STEG distribudon networks, it was not possible withinthe scope of this study to make an overall analysis comparable to that made of the transmission network.It was therefore decided, in agreement with the STEG task force, to concentrate analysis on three zonesrepresentatve of Tunisia's various regions which, as may be seen from Table 4.1, can be divided intothree homogeneous categories.

Table 4.1: KEY FEATURES OF STEG DISTRIBUTION ZONES

No. of mLV h/ No. of mnV per LV RatioZones Efficiency 2/ per LV consumer and NV consumer nSN/mLV

Tunfs 0.907 15 6 0.40North 0.911 27 14 0.52Northwest 0.960 30 26 0.87Center 0.890 25 14 0.56South 0.870 34 17 0.50Southwest 0.970 29 31 1.07

f Efficiency u energy billed/energy supptUed.umLV: Moters of LV circuit.

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(a) the first category groups the regions characterized by low efficiency (Energybilled/Energy supplied) and a ratio of length of MV to LV circuits of about 0.5. Thiscategory includes the North, Center, and South (zone 1);

(b) the second category groups the regions characterized by high efficiency (Energybilled/Energy supplied) even though the ratio of length of MV to LV circuits percustomer is high. This category includes the Northwest and Southwest (zone 2); and

(c) Tunis constitutes a separate category (zone 3), characterized by low efficiency (Energybilled/Energy supplied) and a low ratio of length of MV circuits to LV circuits percustomer. One can predict a prior that nontechnical losses are. higher in this zone (zone3).

4.5 One district was selectd from each category: (i) Nabeul, where farming, tourism andindustry are major activities, is representative of the first category; (ii) Siliana, a rural district, isrepresentative of the second; and (iii) the city of Tunis, an urban district, and Ezzahra, a suburbandistrit, are representative of the third. From the standpoint of electric power supply, these districts alsomeet the following representativity criteria: voltage levels of 10 and 30 kV, both overhead andunderground networks, a thre-phase and single-phase distribution system, and medium and low voltagecustomers. A detailed technical description of the districts selected is provided in Annex 13.

Data Collection and Loss Assessment Method

4.6 Since collection of data necessary to network analysis is an essential prerequisite to adiagnostic study of the operation and management of distribution networks, a detailed questionnaire wasformulated and sent to the STEG task force, with a request to collect data on the following:

(a) the configuration and the physical and electrical characteristics of the MV and LV:uetworks: type, length, and cross-section diameter of the conductors, power level oneach outgoing feeder;

(b) the characteristics of the HV/MV and MV/LV transformers: technology employed, corelosses, Joule-effect losses;

(c) the organization of network operation, control, and maintenance;

(d) STEG's standardization policy;

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(e) network planning; and

(f) procurement practices and procedures.

For the districts studied, maps showing all the MV networks and some typical LV outgoing feeders werecollected and examined. In addition, to enable an estimate of losses on the MV and LV network, STEGdistribution staff were asked to measure power flows Into outgoing MV feeders and to take measurementsat MVILV substations and on representative outgoing LV feeders.

Status of available data

4.7 The data-gathering exercise, and discussions with the staff of various STEG distributionservice units, revealed a lack of the kind of reliable and consistent data needed for distribution networkplanning studies and for continuous monitoring of losses at medium and low voltage levels.

4.8 Examination of maps of the distribution system showed that these are not up to 'late andthat the types of map and the information they provide vary from one zone to another. This findingindicates that neither the map standardization policy nor the procedures introduced for updating the mapshave been entirely successful.

4.9 Archival storage of telemetered data at the Distribution Control Center (Bureau Centralde Conduite - BCC) in Tunis is inadequate. This facility, the only one of its kind in the country, has adaily data storage capacity of only 20 telemeter readings, (i.e., 20 different values), while Its archivalcapacity is limited to 20 values over 5 days. This total storage capacity of only 400 values is clearlyinsufficient, either to enable studies on various situations, or, where necessary, to play back a givenoperating problem. It is therefore impossible to obtain data on the daily peak demand of each outgoingMV feeder in this major district, whereas data is available for the other districts, because the HV/MVsubstation supervisors record and file the hourly loads of all the MV outgoing feeders.

4.10 Measurements of reactive energy are lacking throughout the distribution network.

4.11 With regard to the transformers, data on nominal power losses are available in themanufacturers' catalogues, but the load loss figures are only partly available; these figures are collectedwhen specific measurement drives are conducted.

R eoiedain

4.12 STEG has begun to establish a technical data base on the MV distribution network - aspart of the operation known as Gestion Technique des Ouvrages (GTD). This action should be continuedand completed, making sure that reliable information is collected on:

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(a) type, cross-section diameter, length, and number of conductors, for both the MV and theLV networks; and

(b) installed capacity, equipment type, year installed, and sizes of the MV/LV transformers,supplemented with data on the subscribed power of the consumers supplied by eachtransformer, and on substation sizes (to ascertain the space that would be available in theevent that new transformers are installed).

4.13 A general recommendation is to improve control and updating of the network mappingsystem and of the technical data system and to consider developing computerized mapping, at least byacquiing, as a firt step, a Computer-Aided Design system that can create network diagrams.Discussions on ways to improve the technical data system and to computerize mapping could start as soonas the distribution system planning and load flow model recommended in this study has been supplied.

4.14 Archiving of telemetered data, practiced at the BCC in Tunis and at the Regional ControlCenters, should be extended to all the main substations. It would then be possible to record all thetelemetered data by outgoing feeder. STEG would then dispose of a complete set of data for its studieson the planning and operation of distribution networks. Eventually, STEG should consider collectngtelemetered data throughout its system and storing the data on optical disks, but meanwhile It should atleast move to computer storage of the data recorded manually by the substation supervisors.

4.15 For the LV network, STEG should continue routine measurement of voltage drops in theurban areas, but it would be useful to make some of these measurements on a fixed, representative sampleover a long period (around 5 years), so that changes in the pattern of network losses can be followed.

Loss assessment method

4.16 Once data gathering was completed, technical loss assessment was performed In threestages:

(a) for the districts selected, estimation of losses from the MV and LV networks and theMV/LV transformers;

(b) assessment of losses throughout the STEG distribution network by extrapolation from theresults obtained; and

(c) assessment of transformer losses.

Simulations of network operation were performed using a model that runs on main-frame compuers, butbased on the same algorithms and methodology used with the PRAO model, which runs on a micro-computer, which was given to STEG as part of this study so that the utflity could develop distributionnetwork studies and ensure their continuity.

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Redction of MV Network oiMses

Assessment of MV network losses

4.17 Table 4.2 presents the resuts of the calculations of MV network losses. The table givesthe percentage power loss for each outgoing feeder as well as the percentage of use of the line, i.e., theratio of effective peak demand to total insalled capacity. It will be noted that:

(a) Losses from the Chargula feeder in the city of Tunis are significantdy higher than theaverage for the district, which is 1.22%. This difference can be explained by the factthat this line, although equipped for 30 kV operation, is operated at 10 kV, and the entireload is carried forward to the end of the feeder. This feeder has therefore not beenincluded in the estimation of peak capacity loss in the Tunis urban district, whichtherefore is:

334 6x 100 = 1.34%25007

(b) The Haouaria feeder, in the district of Nabeul, has a high loss rate because it is too long,250 knm, whereas mean feeder length in the district is 81 km; this feeder is therefore notincluded in the esdmate of peak capacity loss for the district of Nabeul, which thereforeis:

1156.8 x 100 = 4.01%28867

(c) The widely varying results in the district of Siliana can be attributed to factors commonto rural networks. The Kesra outgoing feeder carries a low load and is significantlyshorter than the Lakmes feeder (135 km compared to 547 km). This type of pattern canbe explained (and is justifiable in rural networks) by the fact that the main substationlocations are opdmized in relation to the transmission network rather than to the loadcenter of the distribution network. This situation results, in some zones, as in the caseof Siliana, in an imbalance between the load and the length of the MV feeders. TheKesra and Lakmes feeders are thus both included in the estimate of peak power loss inthis district, which is:

11.1 + 0.67x100 = 5.89%2

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Tabte 4.2: NETWORK LOSSES: NV SAMPLE

Peak load Peak power lossDOstrfct/feeder (kW) (kU) X power loss X Line uso

Tonit 2146 20.1 0.83 42Iner 3082 98.1 3.18 54B. Kiled 1936 19.0 0.98 34BCT 2912 23.1 0.79 43Agricuttor 1595 8.2 0.51 26Turqule 1626 7.2 0.44 24El Nafir 29m8 38.8 1.31 43Dwrdet 3206 52.6 1.64 56Avenfr 11 2256 23.5 1.04 33Avenir 22 3020 44.0 1.46 44Chargula 4290 447.0 10.43 76

Nabeut

O. Argoub (1201) 6912 240.3 3.48 48Nazrea (1302) 8319 227.9 2.74 69IeLibla (1304) 5751 263.5 4.58 31Heourie (1305) 5691 607.9 10.68 32Betl (5001) 7885 425.1 5.39 49

Sitiaon

Lakmes 6125 623.2 11.1 24.3Kesra 868 5.8 0.7 20.7

4.18 The overall peak power loss for the STEG MV network can now be estimated bycalculating the average of the individual zones, weighted by the MV consumption for the zone (see Annea13). This may be stated as follows:

(4.01 x 1312.4) + (5.89 x 743.3) + (1.34 x 1125.4) = 3.5%3181.1

Reduction of MV network losses

4.19 IMproved location of t-he main substations: For the MV network, it is recommended tatSTEG reduce the length of the feeders and locate the main substations closer to the load centers of thedistribution network loads. This means that technical/economic studies on the location of mainsubstations should include costs of losses from the transmission and the distribution networks.

4.20 Ktgaaft=ft: Use of larger conductor sizes reduces the losses for equal amounts ofpower transmitted. The method used for calculating "power thresholds" (the power levels at whichreconductoring becomes cost-effective for STEG) is described in Annex 14.

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4.21 This method is then applied to all the MV feeders studied in order to identify thosesegmen whose power level exceeds the "power threshold" at which reconductoring becomes cost-effective. For each possible strengthening, savings are assessed by valuing the MV kW at TD 360.5 (seAnnex 2) and the current annual rat of return' is calculated,j/ defined as the ratio of expected savingsin TID to the total investment cost In TD. The detailed results of these calculations are given in Annex14.

4.22 For the samples studied, these results show that:

(a) in the district of Nabeul, it would be necessary to reinforce 13.34 km of the 695.47 kmof line studied, or nearly 1.92% of the network, in order to reduce losses by a little over0.3%. The mean "current annual rate of returnm for the proposed action would be 32%,and thus the investment payback period would be slightly over three years;

(b) in the district of Siliana, it would be necessary to reinforce 29.5 km of the 682 km ofline studied, or nearly 4.3% of the network, in order to reduce losses by nearly 1.5%.The "current anmnua rate of return" for the proposed action would be 30%, and thus theinvestment payback period would be slightly over three years; and

(c) the network in the district of Tunis is much better adapted to demand. The only changeto be considered is to put the first section of the Charguia feeder underground so as toreduce loses on this feeder from 10.3% to 6.21% at a capital cost of about TID 407,000,recoverable in a litle over 6 years.

4.23 By etrapolaing the results obtained for the samples studied to the zones they represent,we obtain results for the entire STEG distribution network (see Table 4.3).

I/ VT nwsnenpqybckperod nta investmnt/annual saving) or its Inverse, the "current annua rate of return,"is du rditor S~l w edby elec utiltis to evawte the econmcfeasIbUIy of 1s type ofInvesmu. Ane3 provides a table carig the 'crtoal d Intenal rate rseturnfor pero of10, 20, or 30yrs. should be nod dwt nvesmn so redce Ioss Ashoud haw bIedate effects on the network, oterwi,e tllbtnof new generati uft and nhtk exensions change the context wry quick&. An Invesment in ds area ca beconsHered to have a "*ftn" of abowt 10 years. Usbig this hypothesis, it is not adabkle to make an thmenwih a "cmrent aual ra of retn of less t 18%, or wih an investmnt pabcte of ore dt 6 yar,which corresponds to an ieral rate of retrn of 12%.

-41 -

Tabiala4J REOUCTION OF LOSSES FROM WV NETWORKS

Zone 1 2 3 S/ STEG Network

Lenagth of network to bereinforced (km) 103 536 None 639

Cost (thousand 10) 996 2627 - 362T

Peak load savins (kI) 894 2190 3084

Finanttal savings (thousand TO) 322 790 - 1112

Investment payback period (years) 3 3.3 3.3

A/ See para. 4.22(c): the special case of the Charguia feeder tine.

These changes would reduce the loss factor throughout STEG's MV network by 0.5% (to 3.02% fromthe present 3.5%) with a mean payback period of three years. However, it should be noted that manyof fae line reinforcement projects (nearly 20% of them) have payback periods of less than two yeas andshould be undertaken on a priority basis (see Annex 14).

Reduction of LV Network Losses

Awmet f LY netwok lom

4.24 Technical losses from STEG's LV network were assessed for an LV feeder sampleconsidered to be representa ve of the networks in the districts selected; the method used is described inAnnex 13. Since the districts are representative of STEG distribution networks, the overall loss for theLV network was taken to be the mean of the percentage losses calculated for those districts weighted bytheir share of total LV load.

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4.25 Table 4.4 shows the results obtained for the sample of feeders examined:

ble 4.4: PEAK POIdER LOSSES; LV FEEDER SAJPLE

Method of Maximum capacity Losses LossesDistrict LV feeder distribution (kW) (kW

City of Tuntis Hiver Li tri 48.0 5.70 11.9Ezlitouna L2 tri 155.0 5.40 3.5El DJazira L2 tri 41.5 0.80 1.9

Ezzahra Ones L2 tri 50.0 1.80 3.6t ce L2 tri 77.0 4.30 5.6Ohandi L2 tri 16.5 0.40 2.4Kahene L2 tri 39.0 0.70 1.8

Nabaul Ecart Word Al L2 tri 53.0 5.90 11.1Ecart Nord A2 L2 tri 55.6 5.30 9.5Ecart Nord A3 L2 tri 35.0 4.30 12.3Ecart Word A4 L2 tri 63.8 5.70 8.9Kommi L2 tri 80.3 13.55 16.9Karsoline L2 mono 20.9 2.10 10.0

Sflfna Gabre Ghoul 341-Al L2 mono 7.3 0.21 2.9=abre Ghoul 341-A2 L2 mono 2.4 0.03 1.3Sabre Ghoul 342 L2 mono 7.9 0.16 2.0Sabre Ghoul 343 L2 mono 8.4 0.41 4.3

4.26 The percentage losses for each district are then estimated as the ratio of total LV feederlosses to tota maximum capacity, giving the following results:

DP ist Overall LosesCity of Tunis 4.9%Ezzahra 3.9%Nabeul 11.4%Siliana 3.1%

From dis result, we obtain overall LV losses of 6 8 for the STEG network.

Reduction of LV anwk l

4.27 P F balan For the three-phase network, we recommend a better distribution ofload be e phas to prevent curret flow through the neutral and reduce losses, which are proportionalto the square of the current. For instnce, the Kaounia feeder in the district of Nabeul is seriouslyunbalanced, since the urrent carried on the second phase is more than triple the current carried on thethird phase (11 = 100A, 12 200A and 13 = 65A). A better distribution of the load between the threephases, a simple and inexpensive action, would reduce the losses on this feeder from 16.99% to 10.1%.

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4.28 VolX chw=: It is recommended that STEG complete the ongoing change of voltagein the city of Tunis, since the move ftom Li to L2 makes it possible -- for any given power level - toreduce LV network losses by roughly two-thirds. For instance, in the sample studied, raising the voltageof the Hiver feeder from Li (110 V) to L2 (220 V) would bring the present loss figure of 11.9% downto 3.96%. More generally, if all LI feeders in the Tunis district were operated at L2, the district lossfactor would be around 3.3%, instead of the present figure of 4.9%.

4.29 An operation of this kind requires not only that MVILV transformers be changed but alsothat customers' LV elxtrical equipment be adapted to the change in voltage level. The total cost for thisoperation is given In Table 4.5, based on an estimated cost of TD 150 per LV customer.

Table 4.5: EiTINATED COSTS OF UPGRADING THE STEG LV NETWORK TO 220V

No. of IItV N/LVl No. of LV consumers Cost CostRegion substations per STEG LV substation (TO) (USS)

Tunis 168 204 5,140,800 5,710,500North 10 126 189,000 210,000Northwest 0 76 0 0Center 26 121 471,900 524,200South 0 79 0 0southwest 43 98 632,100 702,200

Total 247 6,433,800 7,146,900

It is assumed thia the changeover from LI to L2 on all the feeders considered would save a capacityequivalent to that estimated for the Hiver feeder, namely 37 W/customer, so that total peak demandwould be reduced by 1,587 kW. Anticipated savings would total ID 748,114, or US$831,237, and thepayback period would be between 8 and 9 years. It must be noted, however, that these calculations donot take into account the improvement in service quality that would accrue from the changeover or thefact that much of the equipment to be replaced is already obsolete and needs replacing independently ofany loss-reduction measures. Moreover, the voltage conversion program has already reached an advancedstage and bringing it to a speedy conclusion would make it possible to standardize electrical equipmentin Tunisia; this standardization would have a favorable economic impact considerably greater than themere savings achieved by reducing losses.

4.30 As for the medium-voltage lines, reconductoring is economically justified as soon as losssavings per kilometer are higher than or equal to the ratio between the annual return on the investmentrequired (discounted at 10%), expressed in TD/kW, and the value put on losses from the LV network,expressed in TDflW. For each conductor studied, the "power threshold" beyond which it is cost-effective to change to a larger-diameter cable is calculated. In the case of the STEG LV network, thesecalculations were made on the assumption that changes would be made exclusively to two standardizedcross-sections: 35nmm2 Alu and 70mm2 AMu. Table 4.6 summarizes the results given in detail in Annex14.

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tabla 4.6: NETWORK REINFORCENENT; LV FEEDER SA#PLE

Max. capacity Losses after cost InvestmentDistrict LV feeder (k) reinforcenent (TD) payback period

(years)

City of Tunis Niver 48.0 1 900 15,300 8.3Ezzitouna 155.0 4,823 S20 1.9El DJazira 41.0 459 852 5.3

Ezzahra ones 50.0 1 248 1,053 4.1Indwpedance 77.0 2,050 2,081 2.0Shandi 16.5 *Kahona 39.0 602 347 7.5

Nabeut Ecart Nord Al 53.0 3,331 5,679 4.8Ecart Nord A2 55.6 4 055 3,121 5.3Ecart Nord A3 35.0 1.830 4,769 4.2Ecart Nord A4 63.8 2 658 6 589 4.7Kaounia 80.3 9,324 3,685 1.9Karsotine 20.9 1,206 2,409 5.6

Sitiana Gabre Ghout 337Sabre Ghout 342-Al 7.3Sabre Shout 342-A2 2.4 no reinforcementGabre Shout 342 7.9 USabre Ghoul 343 8.4

4.31 Extrapolation of the results obtained for the samples studied to the zones of which theyare representative Indicates a reduction in losses on STEG's LV network of approximately 3% afterreconductoring of 944 km of lines, almost 3.1% of the LV network, for a total cost of TD 8.146 million,and an investment payback period of around 3.7 years (see Table 4.7).

Table 4.7: REINFORCENENT OF THE LV NETWORK

Zone 1 2 3 STEG network

Length of LV network to be relnforced (km) 832 - 112 944Peak load savinos (kdW) 3950 754 4704Cost (thouuwnd T) 7184 962 8146Finanial savings (thouwsd TO) 1862 355 2217Invstment payback period (years) 3.9 2.7 3.7

It is reconmmended that STEG begin by reconductoring those sections that show the highest rates ofreturn.

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Assesmnt and Red&Ztion of Losses from Transformers

4.32 Losses from transformers forming part of the distribution network are of two kinds:

(a) core losses or no-load losses which correspond to losses by hysteresis and eddy currentsIn the magnetic cores as soon as voltage is applied to the equipment. They are notdependent on load; and

(b) winding or Joule losses, which are those induced by the Joule effect In the conductorsthat form the windings. The manufacturers provide information on Joule-effect lossesat rated power. In calculating losses for a given load, the loss at rated output must beweighted by the square of the coefficient of utilization of the transformer; this coefficientis equal to the ratio of demand to rated capacity.

Lasso in the HY/1M Yenra

4.33 STEG has 74 HV/MV transformers, as follows:

Power in MVA 15 20 25 30 40 50Number 12 2 3 19 37 1

Since the charactertics of the 20, 25, and 50 MVA transformers are not known, it was assumed forcalculation purposes that their characteristics were identical to those of the ones nearest to them in size,which gave the following basis for calculation:

Power in MVA 15 30 40Number 14 22 38

4.34 Table 4.8 shows core losses (CL) and Joule-effect losses (IL) for the three sizes oftransformer selected:

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Tabil 4s.: LOSSES IN THE MV/NV TRANSFORMERS

CLif Nuiber CL JLif NiM er JLTransformers CkV) of trans- (ki) (Wid) of trans-(kd) formers formers

15 IVA 18 14 252 100 14 51330 NVA 23 22 506 160 22 82440 NVA 26 16 416 195 38 2087

34 22 748 - -

Total - 74 1922 - 74 3424

A/ CLI represents individual transformer core losses. JLI representsindividual tranwformer Joule losses.

M: Total joule losses a individual joule losses X (utilization factor)2 .

Losses tal 5,346 kW for a total peak demand of 771 MW, giving a loss factor in the HV/MVtansformers of 0.69%.

Reduon g__ossesinthe HV/MV trnfonns

4.35 Reduction of losses in the HV/MV transformers should be based on a review of:

(a) the operating procedures currently nsed to reduce core losses; and

(b) criteria for reinforcing existng transformers and installing new equipment so as toImprove the transformer utilization factor.

4.36 Qtio gf exisungtransformers: STEG operates its HV/MV transformers by keepingone of them on stand-by - in other words on-line and unloaded - even when peak load is less ta therated output of one of the two transformers available in the substation. This policy is mainly a result ofthe fact at, for roughy a quarter of the main substations, the HV busbar system is constructedaccording to a ring-bus scheme; this means that, in order to disconnect the transformers, various circuit-breakers connecting to the feeders must be opened, and the HV disconnectors of the transformers are notremote-conolled.

4.37 Stricdtly from the standpoint of loss reduction, when a single transrmer is sufficient toprovide power the second transformer should be disconnected if no-load losses are to be avoided. If forany reason there is no alternative but to apply voltage to the second, the more economical course is touse both tranfomers so as to balance loads and reduce Joule-efect losses by half for any given powerlevel. Moreover, disconnecing the second transfonner would not disrupt opeations except in very coldweather, which is unlikely in Tunisia, and would better protect the equipment against voltage surges dueto lighting.

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4.38 The two methods of operation, with one tr2nsformer or with two, were compared. Byapplying the first method to the STEG network, using data for 1989 and a power factor of 0.9, it waspossible to Identify the HV/MV substtions for which operation with a single transformer is economicallymore advantageous (see Annex 15).

4.39 Substantial savings of about 3 GWh and 346 kW of peak demand for the year 1989, witha value of TD 126,000, or US$140,000, are theoretically possible. Nearly twothirds of these savingsrequire no investment, and can be achieved simply by changing the method of operation of eight HVIMVsubstations. A little over one-third of the savings require technical adjustments at the five substationsequipped with ring-buses. It is recommended that STEG:

(a) adopt the practice of connecting only one transformer at the eight substations for whichthis method of operation has been shown to be financially advantageous as well astechnically feasible without any other adjustment. Anticipated annual savings thrughreduction of core losses would amount to TD 78,500, or US$87,200; and

(b) carry out tcchnical/fincial studies for the five substations where technical changes arenecessary, by comparing the amual savings from, loss reduction, about TD 47,800, orUS$53,000, with the cost of the necessary changes (in particular, the cost of remotecontrol of the HV disconnectors).

lQmpViing the transformer uttio fact

4.40 According to data collected for the year 1989, the utilization factor for the HVIMVtransformers in the STEG system is 2.85. I/ Although satisfactory, it could be improved by:

(a) redistributing transformers among the substations to ensure optimal use of this class ofequipment; and

(b) refining the criteria for reinforcing and installating transformers in new substations.

4.41 Exchanging transformers among substations is difficult, considering the many tpes oftransformers currently in the STEG network: 20 different types among 74 units in use. STEG's decisionto standardize equipment should mitigate this problem.

4.42 Substation expansion criteria should take into account possible transfer of flows betweensubstations in cases where a transformer is tripped, and it should be accepted that, at peak periods, therated capacity of the other transformer might be exceeded. Generally speaking, intemational standasallow temporary overloading of transformers by between 1.20 and 1.25 of nominal current. Obviouslyeconomic calculations should allow for Joule-effect losses due to equipment overload.

I/ TVa4brme miftoan facor = wa liuiW capaciy x cos phi + toa peak lod.

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4.43 Finally, it is recommended that STEG take greaer account of the capitalized value of coreand Joule-effect losses over 20 or 30 years when comparing bids to supply transformers. The cost oflosses should be calculated using the Incremental cost of a kW at the HV/MV level. For instance, thecost of core losses capitalized .ver 20 years for a 40-MVA transformer of the type installed at the LaGoulette substaion is nearly TD 40,000, or US$44,000, higher than the cost of losses from a 40-MVAtransformer of the type instaled at the Oued Zarga substation. This amount Is not insignificat andshould be compared to the difference in purchase price between the two types of equipment.

Losses In the MVALV formers

4.44 Assessment of the lossea in the MV/LV transformers was undertaken in the same dlitrictsselected for the study of the MV and LV networks, namely, the city of Tunis, Nabeud, Siiana, andEzzahra (see Annex 13). STEG provided the data on transformer specifications, particularly on core andJoule losses.

4.45 Both core and Joule losses were calculated using the same formulas as those used for theHV/MV transformers SI for al transformers in the Nabeul, Siliana, and Ezzahra districts, and for thetransformers installed on the 11 outgoing feeders selected in the city of Tunis. The results obtained aregiven in Table 4.9:

TabLe 4.9: LOSSES IN THE NV/W TRANSFORMERS

Destrict Nabeut Siltian Tunis-vylle Ezzahra STEG Total

Losses In NW 1.2 0.4 0.6 5.6 23.1

X of nsx. capacity 3.0 S.6 2.1 2.1 3X

4.46 In the Intere of loss reduction, the report recommends redistribution of thosetrasformers that are not being used optimally. For a given type of transformer, the method used consistsof calculating losses in kWh over a year, then comparing the cost of these losses to the cost of movingthe transformer. Moving the transformer is economically justifiable if the cost of moving it is less thanthe difference in loss costs between the transformer proposed to be moved out and the new equipmentto be installed. Calculations were made for nine classes of STEG MVALV tansfrme. Theydemonstrate that, for the l0-kV network, improved management of 500 and 630 kVA transformers would

/ TformaW wedjbr ctomwr sranrmwrsa ders sIightl from that wed for the SlZW networks:

JL = Jonu lasrs at rated owp, taurr sucfed w-werPoal customer dsm capac;

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lead to annual savings of TD 6,885, or US$7,500. Similar calculations could not be made for all classesof transformer, however, since their utilization factors, particularly at the 30-kV level, were not available.It is recommended dhat STEG make these calculations, based on utilization factors determined followinga measurement campaign. STEG's decision to eliminate the 400-kVA class of transformers from the 10-kV system should be reviewed and carefully scrutinized in light of the redistribution of power demadamong MVALV substations and of the usefu life of the 1O-kV network.

4.47 Widely differing data were obtained on the number of MV/LV transformers In cureninventory, ranging from 2,050 (10% of the number in use) to 7,852 (38% of the number in use). Bothfigures are too high, and substantal savings could be achieved through suitable adjustment of inventorylevels. It is recommended that inventory be limited to 5% of the transformers in use, which wouldpermit annual savings of about TI) 263,000 to TD) 1,740,000, or US$290,000 to US$1,900,000,depending on the real extent of current inventory.

T3bJe 4JQ: SAVINGS ACHIEVABLE BY REDUCING THE INVENTORYOf NVALV TRANSFORNERS

ExcessIn Current Recommended Excess cost of Annualuse inventory Inventory inventory inventory (TD) savings (TO)

20361 7852 1018 6834 10.251,000 1,740,00020361 2052 1018 1032 1,548,000 263,000

lhe cost of superfluous inventory is estimated using an average figure of TD 1,500 per transformer, orUS$1,700 (taking into account the age of each set), while annual savings are estimated at 17% of totalinventory value (15% in holding costs and 2% in procurement costs).

Rea -w m mMad

4.48 Any energy transmitted by way of alternating current consists of active or useful powerand reactive, non-usel, power. Reactive power is induced by the effects of electromagnetic fields; inother words, reactive power is magnetizing energy.

4.49 Distrbution networks always consume reactive energy because of:

(a) applications that exploit the properties of magnetic fields (static or spinning) rather thanthose of elecrcal fields; and

(b) the structre of the network itself, since the reactive energy consumed by lines andtransformers is greater than that produced by cables.

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4.50 The objective of reactive power compensation policies is to prevent the networks fromcarrying a parasitical flow of reactive energy, and hence to reduce network losses and voltage drops.From the technical standpoint, the ideal solution is to produce reactive energy at the point ofconsumption. From the economic standpoint, the optimal solution is the one that ensures that the averageannual capital cost of providing one supplementary Mvar of compensation equals the cost of the activeenergy losses occasioned during the year by the generation and transmission of one addkitional Mvar atpeak periods while maintaining voltage levels at the various points in the network.

4.51 Reactive power compensation policies are based on two types of measures:

(a) technical measures that the power company implements based on their expected economicreturns; and

(b) regulatory and tariff measures, generally implemented to encourage large consumers ofreactive energy to generate it themselves, using their own equipment, or to consume lessby improving the energy efficiency of their installations.

4.52 Since the flow of reactive energy burdens upstream networks, the study of the technicalmeasures needed for the STEG networks was conducted at the transmission network level. The resultsshowed that supplementary compensation amounting to 124 Mvar is needed as soon as possible in orderto reduce tan phi to 0.5 % (see tecbnical and economic justification, para. 3.16).

4.53 With regard to tariff measures, STEG's method of billing the reactive energy suppliedto its HV and MV customers gives them little incentive to install compensation equipment. Exoneratingthese customers from payment for the reactive power they consume up to a level equivalent to 75% oftheir active energy consumption, and applying surcharges (or penalties) to consumption above this levelis not consistent with the effort to reduce tan phi to the target ratio of 0.5.

Reactive power billing

4.54 In France, the power distributor supplies reactive power free of charge at the point ofdelivery under the following conditions:

(a) up to the equivalent of 40% of the active energy consumed (tan phi = 0.4) duringscheduled or unscheduled peak hours and during full-load hours in winter, fromNovember to March;

(b) without limit during off-peak hours in winter and throughout the summer tariff period,from April to October inclusive.

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When the limits are In force, any reactive energy consumed beyond tan phi = 0.4 Is billed monthly atthe rates listed in current price schedules (e.g., 12.65 centimeslkvarh for the 'green' tariff, applied overa range of 250 kVA to 10 MW).

Consumption is billed as follows:

Wa (kWh), for the energy consumed per month during the period subject tolimits;

Wr (kvarh), for the reactive energy consumed per month during the periodsubject to limits;

Wfr or 0.4 Wa, for the amount of reactive energy supplied free of charge;

The amount of reactive energy billed will be: Wb = Wr - Wfr = Wa (tan phi 0.4). The charge willbe: Wb x a, where a is the price of reactive energy.

4.55 The sudy of the STEG MV network showed that it is not overloaded and that a decisionon a voltage change, particularly from 10 kV to 15 kV, is not urgendy needed. However, in view of therapid growth in MV and LV consumption in Tunisia, to avoid saturation of the network and increasinglosses, a change in voltage, particularly the economic timeliness of a change from 10 kV to 15 kV,should be studied, and incorporated into a relatively long-term MV network development strategy. STEGdoes not currently conduct planning studies of this type on the distribution network, as it does not havethe necessary tools (distribution models) and computer resources.

4.56 It is recommended that STEG develop distribution network planning studies for themedium and longer terms, using the model and data-processing resources acquired through this project.During a first phase, these studies would be camed out at STEG headquarters, but they shouldsubsequently be decentralized to the regional and/or district levels, once their scope has been defined atthe plant level, and once it has been nastaied at the regional level that the specialized personnel neededto conduct such studies are avaflable.

Additional Problems Associated with Operation of the MV/LV Networks

4.57 Two other problems associated with operation of the MV and LV networks should bementioned: maintenance of MV/LV structures, and environmental and safety problems created bytransformers and capacitors that use pyralene as a dielectric.

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Maintmenn

4.58 The maintenance of MV and LV structures is generally fairly satisfactory, but varies fromone district to another because STEG has no stated maintenance policy, and there are no writtenprocedures for the various types of structure.

4.59 As with its other functions, STEG should study and implement measures for themaintenance of MV and LV structures that will guarantee an acceptable level of reliability at least costand should prepare written procedures for use by the MV and LV network operators. Annex 16 presentsthe issues to consider in preparing a study of this type. A maintenance study would provide a goodopporunity to decentralize STEG management and give greater decisionmkaldng responsibilities tooperations personnel. Particular attention should be given to the levels of expertise required and toarrangements for internal monitoring of maintenance.

Prention of risks associated with the use of PCB

4.60 Eivironmental studies the Bank has conducted in Tunisia, as well as discussions withsenior STEG officials, have indicated that STEG fully understands the risks associated with equipmentthat uses insulants containing PCB (polychlorobiphenyl) or PCr (polychloroterphenyl), and that the utilityhas undertaken protective measures as well as measures to sensitize customers who own equipment of thistype. The report recommends that STEG strengthen and systematize preventive measures to be taken incase of accident and increase its efforts to inform and sensitize its customers. In future, STEG shouldavoid installing equipment with insulating oils containing PCBs.

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V. CUSTOME MANAG13hEN

5.1 In addition to reducing technical losses (see preceding chapters), STEG needs to Improveits customer management so as to minimz the financial losses it incurs when the power it supplies isconsumed. These losses, called "nontechnical" to distinguish them from the technical losses discusedearlier, are associated with:

(a) recording consumption (metering);

(b) customer billing; and

(c) debt recovery.

5.2 The program introduced some years ago to improve customer management has enabledSTEG to reduce customer losses to a low level. For the distribution network, for instace, the studyarrived at a fige of 10.3% for overall losses in 1989, 7.2% technical and 3.1% nontechnical. STEG'sperformance in this area is comparable to that of more advanced electric utilities. The utility needs,therefore, to consolidate its gains through rigorous management of the existing system and to progressfurer by adopting technical and organizational management techniques that are new to Tunisia.

Meterine

5.3 Losses at the metering stage have three possible causes:

(a) unmetered consumtion (llegal connections and temporary installations);

(b) third party interference with metering; and

(c) technical defects in the meters.

Unmetered cosm ption

5.4 It has become clear through field visits, review of connection procedures, and disionswith customer management staff that the risks of unmetered consumption, though present, have beenminimized.

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5.5 I N: To avoid this problem, frequendy observed in peripheral urban areascharteized by uncontrolled development, STEG has established a highly deterrent policy, based on thefollowing:

(a) meter readers routinely monitor the network and meters, and are required to report alltechnical and administrative anomalies they observe on their rounds;

(b) meter readers are rotated frequently from one district to another to minimize the risks ofcollusion with customers;

(c) as an incentive to meter readers to detect frauds, STEG offers them a bonus of TD 5,about 50% of a supervisor's average daily salary, for each case of fraud they identifzy;

(d) STEG uses insulated cables for networks and supply lines, making clandestine hook-upsdifficult; and

(e) stict internal anti-fraud regulations provide for the denunciation of frauds by officiallydesignated staff; such denunciations are followed by legal action, since the Tunisian PenalCode equates theft of electric power with fraud.

5.6 To warn against and prevent the spread of illegal connections and other types of electricityfraud, STEG should organize swift, targeted field operations to increase consumer awareness of fraudand prevent its occurrence. To be effective and have a major impact, such operations should be precededby finetuned statistical analyses (see para. 5.12(a)), widely publicized in the appropriate media, targetedto specific geographic areas and to high-risk customers, and conducted over short time periods bymobilizing the required staff and physical resources.

5.7 Anti-fraud campaigns of this type are not costly. For instance:

(a) a half-day campaign conducted by 10 STEG staff (1 executive, 2 foremen, and 7operatives) would cost about TD 104; and

(b) an anti-fraud team tackling one type of problem (large customers, delinquent customers,billing anomalies) over a 400-hour period would cost about TD 1800.

The cost would be recovered by reducing frads by an average of 1.5 MWh, in the first case, and 28MWh in the second.

5.8 However, the major benefit from actions of tis type is psychological - they warn againfraud and deter potental evaders. Experience in various counties shows that fraud spreads rapidly andis difficult to eradicate once it becomes pervasive. Systematic analysis of the results of the campaignsit has carried out so far will give STEG a more accurate idea of their effectiveness and of what

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organizational changes it can make to continue the campaigns and incorporate them into its interalmonitring program.

5.9 Tempom lInstallations: An in-depth analysis of the procedures STEG has developed toprevent unmetered service connections (following a breakdown in meter inventories or requests from theautrities for urgent hook-up) shows that these are well designed and complete. They appear to be well-applied in the distribution districts. To minimize financW losses, STEG should continue to apply themforcetully.

5.10 ,nterteg by third parties: Meter fraud is increasing in many countries. The fraudgenerally consists of modifying or damaging the meter to reduce the amount of energy registered, or toensure that it is not registered at all. Subscribers commonly use simple methods (damaging the meterItentionally, immobilizing the disks, applying magnets, etc.), but more technically sophisticated methods,which require th complicity of STEG employees or professional electricians (by-passing the meters,additional conneL -ons made in series, and resale of the energy to take advantage of a special tariff) arealso observed.

5.11 STEG is making great efforts to eliminate practices of this kind, through:

(a) regular meter monitoring (see para. 5.5);

(b) routine meter inspecdon campaigns;

(c) printing of meter cards for disconnected customers as well as for regular customers; thedata processing equipment reads and checks these cards, and automatically indicates anyfraudulent consumption;

(d) producing a computerized listing of subscribers who have abnormally low consumptionor none at all.

5.12 Three actions are recommended to consolidate STEG's achievements, simplify meterreading, improve checks and controls, and introduce new meter reading techniques:

(a) increase the use of data-processing techniques to detect abnormal consumption due tofraud or metering anomalies, through routine monitoring at the central level, during thebilling process, by (i) comparing the customer's current consumption with pastconsumption, if a record is available, and/or with average consumption for the categoryto which the customer belongs (this requires defining homogeneous customer groups, andstandard consumer profiles); and/or (ii) monitoring the use of subscribed demand. Theresults can be used following various crite6a, adjusted for each district; the urrtreading may be rejected, forcing a re-reading, and/or consignment of the invoice to aspecial category; or an error message may be produced, addressed to the operating entity

-5S6 -

cnned, which would decide - in light of local conditions - on the course of actionto be followed. To supplement this automatic control mechanism, and to ensure thatlocal controls a better designed and targeted, STEG could give local ma sagers accesto customers' fles, using a simple interfice device. Initially, the districts could accessabbriad customer files of the type that can be processed and used on a PC. Decisionsas to the kinds of processing to be undertaken, the hardware configurations to be usedlocally, and the cost of the operation should be incorporated into STEG's master data-processing plan, which should be developed in close association with local magers;

(b) install meterson the outside of buildings, to reduce the number of missed readings, detorfraud, and simplify the detection of fraud and meter anomalies by making meters moreaccessible to STEG staff. Even if the problem of aceessibility does wt seem too seriousat present, STEG should study a policy of maintaining permanent access to meters, takinginto account the economic and social problems unique to Tunisia and the types ofmetering technique now available (the relevant technical information can be found in anannex to the report that the Consultant has submitted to STEG). In France, the additionaloperating costs due to meter inaccessibility have been estimated at F 250/year/inaccessiblemeter, or 5% of an average annual bill (in Tunisia's case, this would amount to TD 4 at1989 prices); and

(c) gradually introduce electronic metering methods. These methods may be more reliablemd accurate because they monitor the maximum load, are more complex to defraud, andcan accommodat multiple and complex tariffs when necessary.

5.13 TIchnjLdfecsIn. meter: By following a strict policy of surveillance by meter readersand conducting meter calibraion campaigns at irregular intervals, STEG keeps meter defects at aminimum throughout its networks. The report recommends that STEG:

(a) formalize its meter verification procedure, following a clearly stated schedule, taking intoaccount both the risks of loss of revenue and the capacity of the regional calibrationcenters. Yearly intervals are proposed for large-scale customers, and a realisticallydetermined schedule for all others; and

(b) computerize management of the meters in use; with computeriza3ion, a series of meterscan be analyzed statistically to detect operating problems, and steps can be taken toreplace, repair, and/or calibrate the defective meters. STEG should study such a systemin the context of its overall data-processing plan, to determine what types of infrmadoshould be included and link it with the customer data file. If computerized managementproves too complex or too costly because of the large number of meters in use, STEGshould consider alternatives such as gradually building up a data file on the metersasigned tO new customes or a file on new and overhaued meters - in the medium term,the data would provide an adequate stistical base for rigorous meter management.

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If either one of these alternatives proves too hard to implement, STEG should at leastdevelop a PC data file of meter readings for the large MV-users, and for multi-ratemetering; about two man-months would be needed to set up the file.

Cua=me Billing

5.14 Customers are billed automatically from two centers in Tunis (two mini-computers) andone In Sfax (one mini-computer). Billing is generally satisfactory - STEG agents deliver statements tocustomers' business address or residence within three to five days. Customers are not billed by mail, aspostal services are considered unreliable. The new customer-oriented computer application that is beingdeveloped should improve the present billing system. The probable causes of losses, and theImprovements to be made over the complete cycle, from connection of a new customer to issue of thebill, are reviewed. below.

Eoxging j§ amm

5.15 . Delays in registering new customers (meters) in the billing files or in updating the filesin response to metering or address changes can lead to late payments, or to loss of income for the utilitydue to failure to bill.

5.16 The procedure STEG has instituted is reliable and should prevent situations of this typewhere ordinary subscribers are concerned. However, the procedure must be stricdy applied to allhirerarchical levels, and it would be advisable to extend it to all classes of customer, including localauthorities and government bodies and agencies. The report also recommends that STEG use as itsmanagement criterion for the districts "number of subscribers awaiting inclusion for more than twomonths," to replace the existing criterion of "number of subscribers awaiting inclusion for more than fourmonths." This new criterion, which puts more constraints on management, would improve the utility'scash flow and enable annual financial savings of about TD 2,300, or US$2,500.

Mlewe reaing

5.17 Meter-reading losses may be caused by errors in reading, recording, or transmtting themeasurements, by collusion between the meter reader and the customer, or by the customer's absenceat the time the meter is read. STEG has introduced several operating practices and procedures that haveImproved the quality and reliability of meter readings, as follows:

(a) at the district level, meter readings are no longer entered manually in a register, but aerecorded on computers;

(b) particular attention is given to recruitment and to providing regular additional training;

-58-

(c) meter readers are rotated regularly from one zone to another to avoid collusion, theeffects of routine, etc.; and

(d) readers are monitored individually for the quality of their work.

However, meter Inaccessibility i beginng to cause problems (see para. 5.12).

S.18 STEG should maintain and further develop its program to train meter readers and improvethe quality of readings. Simultaneously, it should begin studying and introducing - even if only on anexpeimental basis - more advanced customer management methods such as the use of portable datareaders to record readings.

M QgMbci al-trf customers

5.19 Losses are principally due to insufficient monitoring of customers who benefit fromspecial tatiffs and of unuthrized access to these tariffs by some customers (e.g., some customers havetwo meters at the same address, one of which benefits from a special tariff, such as STEG's special tarifffor tgricultural uses). Although STEG has instituted hierarchical procedures and controls aimed ateliminating error and fraud, it should consider:

(a) supplementing internal hierarchical controls with specific statistical monitoring ofcustomers who benefit from special tariffs - see para. 5.12 (a); and

(b) eventa ly, eliminating special tariffs and disallowing multiple metering at the sameaddress.

Wiling produre and correction of anomalies

S.20 STEG's billing procedures and the associated controls it has set up are reliable; undernormal cirm c, they prevent any failure to bill energy consumption measured or arrears due.Established procedures eue that billing anomalies and bill correcdon are monitored regularly andsysematically and are subject to strict controls at all hierarchical levels.

5.21 STEG should strengthen its internal controls, focussing on correct application ofprocedures. In particular, it should improve the current arrangements for handling billing anomalies byusing its data-processing capability to pinpoint anomalies that have been identified but not dealt with (i.e.,in cases where bills have been confirmed or corrected), within a period to be determined, but whichevidendy must be sboer than the usual billing interval.

-59 -

5.22 Distrilution of STEG bills is efective, given that meter readers deliver them to thecustomers' reskdences or places of business within three to five days of the last reading. However, thiesarra-gemente are quite cosdy. STEG accounting records show that hand delivery of bills costs TD244,833; since there are two deliveries per cycle, the total cost per cycle is TD 490,000. lhe estimatedcost of mailing bills is only TD 390,000, on a per-bill basis of TD 0.15 in stamps and TID 0.0125 in

iscellaneous costs. By mailing bills, therefore, STEG could achieve gross savings of TD 100,000 perbilling cycle, which amounts to TD 300,000 per year (US$330,000) at 1990 prices.

5.23 Although it is difficult to provide a more precise calculation of the effect of these twomodes of distribution on STEG's cash position within the scope of this study, the above simplecomputaion, considered together with the rapid increase in the number of consumers of electric power,indicate clearly that STEG should monitor changes in the postal services closely and start to use themals as soon as they are judged to be performing well enough to answer its needs at least cost.

5.24 STEG should conduct regular pilot mailing tests and begin dispatching bills by mail assoon as this becomes more advantageous from the cost standpoint at the same level of service. Urbanand nrua zones could be treated separately.

5.25 In recent years, STEG has taken several steps to improve recovery of outstanding debts,by:

(a) computerized repeat billings of unpaid invoices, routine and monitored;

(b) adaptation to special or seasonal customers - e.g., meter reading, billing, and colledionare performed every two weeks when the vegetable oil mills are opeting;

(c) use of a special indicator (number of days of accounts receivable oubtanding), includedin district performance charts, to monitor customer arrears;

(d) offering customers the possibility of paying their bills by mail;

(e) negotiation with central government departments and agencies of special provisions(budgetzed prepayment), providing for them to pay 80% of their electric power coss toSTEG at the begning of the year, and 20% at the end of the year (against prsntat_onof statements of actual consumption). STEG hopes to extend these agements to thecommunes in the near fSturt; and

-60 -

(t) disconnection of customers when the first bill is in arrears, and initation of legalproceedings for recovery when the second bill is not paid.

5.26 These measures led to a reduction in customer arrears from 64 days of turnover in 1984to 49 days in 1985 and 30 days in 1988, as Table 5.1 indicates. It should be noted that 75%-78% ofarrears are owed by govermmental agencies, local authorities, and public companies, whose relative shareof debt due rose slightly between 1985 and 1988.

ITLbteL51: CHANGE IN DEBT DUE TO STEG (1985 to 1988)(in Tunisian Dinars)

Year 1985 1986 1987 1988

State-funded consumers 2,801,159 4,396,899 3,888,928 5,249,250Consumers with autonomous budgets 2,161,566 1,316,651 1,233,360 1,421,023Local authorfties 8,938,854 9,984,765 7,672,618 7,510,415National companfes and public agencies 6.038,607 4.879.219 4.039.243 271

S-total 1 19,940,186 20,577,534 16,834,149 16,451,052

% of total 75 75 73 78

Industrial WV consumers 1,582,874 1,509,524 683,767 428,236Nisceltaneous claims for payment 1,119,451 1,578,931 1,822,955 1,826,297Regutar LV consumer 3s805.2d2 3.800294 3.635.867 Al"AGA

Sub-total 2 6,507,607 6,888,749 6,142,589 4,531,621

X of total 25 25 27 22

Total outstanding debt 26,447,793 27,466,283 22,976,738 20,983,673

Turnver 193,395,850 203,108,671 23i,624,963 256,939,417

Ratio (days) 49 48 36 30

5.27 Although considerable improvement has been made, there is still room for futherreduction of the arrears ratio to 20 days of turnover - the average figure for some of the highlydeveloped power companies, while those with the best-managed debt recovery programs show ratios of15 days. Reducing STEG's arrears ratio by 10 days would reduce arrears by TD 7 million, or US$7.8million, enabling cash flow savings of TD 700,000 (US$780,000).

5.28 If STEG is to achieve this goal, it should:

(a) prepare statements quantifying the effect on its financial position of late payment bypublic and parastal entities, and iniate action to improve debt recovery; in particular,STEG needs to: (i) improve its budgeted prepayment procedure and assist companymanagers when they prepare their electricity budgets, to avoid difficulties in collectingthe balance due at tho end of the year - a common problem for STEG, principally dueto agencies' undrestimation of their power expenses when they prepare their anmual

-61 -

budgets; and (ii) extend budgeted prepayment to local authorities, adapting it as necessaryto meet their particular circumstances;

(b) launch campaigns to encourage professional clients to make their payments by means ofdirect debits from their bank accounts, to improve the recovery of large debts; it wouldbe particularly advantageous to propose this formula to national corporations and publicauthorities; and

(c) integrate into the data-processing applications now being developed an indicator thatwould monitor arrears according to the number of days - 20, 30, and 55 - that they areoverdue; this indicator would provide a better reading of the age of the debt and wouldmake debt-collection personnel more aware of the problem.

5.29 STEG could improve both cash flow and debt recovery by:

(a) reading the meters of large-scale LV customers every two months instead of every fourmonths. The preliminary detailed calculations contained in the Consultant's report showthe advantage of bi-monthly meter reading and monthly billing of customers whoseannual consumption exceeds TD 600;

(p) offering a monthly payment system that would enable customers who wished to do so tospread their electric power expenditure over the whole year. Interested customers wouldmake 10 equal monthly payments, calculated on the basis of their previous year'sconsumption. At the end of the year, the balance owed on actual consumption during thecurrent year would be settled over one month or two. In France, estimates show thateach customer who opts for the monthly payment plan saves the power company 0.8%of his annual bill. Assuming this figure applies for STEG also, if only 10% of custome.schose the monthly payment plan, annual savings of TD 65,000, or US$72,000, wo?uldbe achieved.

These preliminary results show the interest for STEG in undertaking in-depth studies in these two areasand, with regard to the monthly payment plan, in making test runs to try out customer reaction to thisnew service and get more accurate estimates of the profitability of the approach.

.9

-62 -

Tariff Poli

5.30 Since 1971, several studies havebeen made of STEG's tariff system, lading to ninetaffadjustmens over the period to preserve the udlity's financial balance.

5.31 STEG bas its pricing policy on charging for power at its marginal cost and keepingraes in line with the cost of providing electricity. Notwithstanding, some problems persist in the areaof LV service because the utility bas retned some preferential rates and others that are based on specialuses.

5.32 It is recommended that STEG:

(a) study the elimination of preferential and special tariffs, to avoid distorted signals toconsumers and, consequenty, waste of energy. By way of example, the LV tariff foragricultural users (not applied during peak hours) is equal to if not less than the generalHV tariff, although LV supply costs are appreciably higher than HV supply costs. If theauthorhies wish to subsidize certain consumer groups, it would be preferable, in theinterest of economic consistency, sound management, and transparency, to choose directmethods of subsidization rather than to distort prices; and

(b) decide quicldy on an LV hourly tariff to offer to all large-scale LV customers as well asto customers who benefit from special-usage tariffs for purposes such as central heaig,air conditioning, and water heating. An hourly rate tariff could even replace specifictariffs such as the one available to 'vegetable oil mills and the like." An hourly ratewould simplify the tarff system and, consequently, customer management, since it wouldeliminate double metering at the same site, a siuation that geneaes additional expsand can lead to fraud.

-63 -

VI. CONCLUSIONS

6.1 This diagnostic study has shown that investments and measures to reduce network lossesand save energy are possible and can produce economic returns even in a utility that performs well, suchas STEG. In addition, these actions and investments have a positive, though modest, impact on theenvironment.

6.2 Measures that make the supply of power more efficient are important and relatively easyto implement since they are based on decisions made at the central level and STEG gives them sustainedattention. However, these measures can be complemented by measures at the final user level (these areharder to implement, but STEG's organizational capacity is adequate to the task), which can contributejust as much, or even more, to Improving the overall efficiency of the electric power sector.

Maictionm roosed

6.3 The main actions and investments proposed are summarized in Table 6.1. The proposedprogram would enable STEG to reduce peak power losses by about 1.5%, or by about 10 MW curreny,and by about 15 MW by 1993. Ihe reduction in energy losses can be estimated as 2% to 3% of totalelectricity consumption.

Tgbte 6.1: MAIN ACTIONS PROPOSED

Annual Payback Rate ofActions Costs savings period return

CUSS 000) (US$ (000) (years) CX)

1. Set up continuous economic efficiency 1,000 1,250 ' 1 > 100monitoring of steam turbines

2. Reinforce NV network 3,300 1,300 2.5 40

3. Reinforce LV network 9.000 2,500 3.6 28

4. Better management of NV and LV transformers Low 150 - -

5. Decrease the cuwtomer portfolio to 20 days Low or 780turnover nit

6. Other foprovement actions: maintenanew Low or 1,720technical and financial ement nit

-64 -

Imp acon the snroment

6.4 The recommended measures, to improve generating unit efficiency and reduce networktechnical losses, will have a beneficial, though modest, impact on the environment;

(a) improving the performance of the steam turbines by at least 1% would be the equivalent,in 1990 conditions, of reducing fuel consumption by about 9,000 toe, or almost 400 Tl,which cowresponds to a reduction in CO2 emissions of about 90,000 t and a redfiido2 inNOx emissions of about 240 t; f/

(b) a reduction of technical losses by about 1.5% of peak demand corresponds to an averagereduction of electricity consumption of about 2.5% and to fuel savings, under 1990conditions, of about 30,000 toe, or almost 1,350 T1. These savings correspond to areduction in emissions of about 300,000 t of CO2 and 850 t of NOx.

6.5 EstImations of the economic impact of reducing emissions from utility plants vary greatly,in a range of 1 to 10, according to different studies and different technical experts. By totaling thesavings considered in the present study at the cost for reducing the emissions, one obtains a value ofUS$7 million, indicatng the supplementary beneffts to be obtained from the proposed loss reductionprogram, about half the sum of the investments proposed to accomplish the loss reduction program.

PoQW csatio the amvlW of fn us

6.6 Many electric utilities in the developed countries, faced with the problem of finding thesites and capt needed to increase the power supply, have undertaken programs of promoting customerconsvaton of energy. STEG has the required organizational and management capacity to promote thesekinds of ptograms, which have been proven to be economically and financially advantageots in severalcountries.7/

6.7 Ilvesdgation of the techncal, Cconomic, and financial conditions required to implementsuch a program is beyond the scope of the present study, but stdies conducted in severd countries havedemonstrated the advantage of such programs, precisdy targeted and supported by adequate financialresources. It is therefore recommended that STEG create a task force to study:

mNote dt, to inyrove th perfawe of te elecic gerang stem and so redwuce te cowapyin offuel per GMVpreced, MGha0 thakene decio to iall a 300MW combnd cyce plant Ts decision, wIcfh wiX allwSM to beer eute dw tehcal and econm paers of tie combhied cyck, wi udote ha a*4g*swcant pcf STa IG's generaing syem an, conseque*, on thistechoo in te region

ZI Ape*ne has wt elecrk sutilie, palcurly in the Unied Sas, have given p the ea*V soluon - toincuase* - in repose to de pressmre ofn l costrans and soMge qfsiab sies, on e one hnd,ad so he ety of indentproduers ito the marke t pail deregulaton of he sector, an the odter.MG can reachth innvati phse Iewwtinin wiho waiing to be co*td w*h tee conorio, and cths redau the weed fr large invem tat arreadaces.

-65-

(a) in association with the Agence de Matris. de i'Energie, the promotion of progrmsdesigned to save power at the level of final use, that are economically and finanlalyprofitable for the utility, the consumer, and the local authorities, and

(b) implemion of the programs by providing better information to consumers, possiblyin association with any partrs, local authorities, and or private promoters, who wouldbe affected by the promotion of such programs.

-66- A lIPage I of 2

STEG ORGANIZTIONAL SMRUCTURE

STEG 'a managed by a Board of Directors with 14 members:

-1 Chairman and Managing Director- 1 Assistat Managing Director- 8 Directors represen the State- 2 Directors representing employees-1 inancial Controller- 1 Technical Controller

Ten Directorates and five Departments, reporting to the Chairman and ManagingDirector, are the backbone of the company's structure.

'he five departments are:

- Management Audit- Internal Audit- Technical Audit- Public Relations- Central Services

The ten directorates are:

- Data Processing- Planning and General Studies- Distribution- OpeatiGas- Equipment- Gas- Financial Affairs- Legal and Adminisrative Affairs- Procurement and General Resources- Rosearch and Development

- 67 - AM IPage 2 of 2

BOARD OF DIRECTORS

Nartagement Audit|Chairman & anaging Director Internal Audit

Lea l Advisors Teehnfeal AuditlAssistant anagn Director Contract Comittee (Permanent)

Pubtic Retations . . . ~~~Centrat Smfervce

H DlstrObutlon j |~~~~~~~~~Leatan Adofnistr tlon e

Operations IAffafrs

Procurenent andEquipoent General Resources

_ _ _ _ I Research andGas . eveoprent

Pltaming and General| Studle D | ats Processing

IF oat ion

-68- Amu 2Page 1 of 19

CALCULATION OF LOSSES

METHOD

Short-term Maryinal Cost

1. The short-term marginal cost is the generation, transmission and distribution cost entailedin supplying one additional kWh in a given year with a fixed amount of equipment.

2. The short-term marginal cost is based on the establishment of a reference cost for fuel,based on the load curve at J-1 or a study of projections. The reference cost takes account of the real costof fuel and an opportnity cost that takes account of real-time contingencies in fuel supply. In the caseof projections, It is necessary to add unit start-up costs (usually from 45 minutes to one hour of fuel costat full plant load), together with transmission costs. The marginal short-term generation costs are usedfor projecdtg operating costs. In France, the reference costs over five years are based on fuel costs.These costs are updated in line with changes in the macroeconomic situation and discount rates.Projections of hourly or daily marginal costs make it possible to optimize allocations in accordance withprobable availability and problems with generating equipment. Likewise, they enable an optimumgeneration schedule to be determined. For Tunisia, a five-year study of marginal generation costs wouldcompare the economic benefits to be derived from either operating the power plans simultaneously, asis done at present, or staggering unit shutdowns and startups.

Long-Term Maginal Cost

3. The long-term margina' cost is the additional generation, transmission and distributioncost entailed in supplying one additional kWh in any given year in cases when the utility is able toincrease generating capacity. It takes ito account fuel, operating and capital costs. Long-term marginalcost Is also calculated on the bas13 of the incremental cost. In fact, the system is adapted to the new loadlevel by making the necessay capital investment one year ahead of schedule. The cost of this earlyinvestment is the sum of the following three items: the annual financial charges (discounted),

-69 - pAnnPage 2 of 19

depreciation over the first year, and the fixed costs of operation and maintenance of the equipment forone year.

4. The esdmat savings from loss reduction (presented below) are calculated by taking intoaccount the ncremental costs of equipment at the various study levels (generation, transmission, anddistribution), as well as fuel costs.

Calltging Fue Cost

S. The 1989 load duration curve for all Tunisia was used to calculate fuel costs. The resultsappear in the ZTEG tariff study of April 1988.

Loa Duration Curve (see Fig. 1)

6. This is the curve showing demand for the 8,760 hours per year, in decreasing order, fromthe maximum to the miniWmum load peak. The load ' urve for generation at national level in 1989 hasbeen used. It is based on 13 values, as shown in thetable in Figure 1.

7. Calcuations would have been more precise if the load duration curves for each of theHVIMV subsaons had been used, because consumption paterns can vary depending on the type of areasrved (e.g. urban and predominantly residential areas, urban and predominantly industial areas,gricultral areas, sparsely populated areas, etc.). In addition, the load diagram for high-voltage

Indusi om ers may also differ from that of customers connected to the distribution network Thenational load duraion curve refers to an annual duration of peak power utilization totaling 5,830 hours(see section below). The annual duration of peak power utilization for the main substations in questonis about 5,900 hours. The difference is thus negligible.

8. It is therefore proposed that the load duration curve for the country as a whole be usedin determining the share of fuel oosts in the anmual cost of I kW of losses at peak periods. This approachis consistent with the degree of accuracy of other data used in the various calculations of loses.

Marginal Cost of Fuel

9. The STEG tarff study gives marginal fuel costs for 1994 for the peak, day and nighttariffpeods based on both domestic Tunisian prices and intemrational market prices. The latter valuwill be used, since they reflect the real cost to the country.

-70- AM2Page 3 of 19

10. Available data relate to different time periods, since we have:

- the load duradon curve for 1989; and

- the margina fuel cosS for 1994.

11. However, the curve for 1994 is likely to be very similar to that for 1989. In fact, noextensive equipment modifications are planned for the short term, and even !f new applications developor pricing adjustments are made, they would not have a significant Impact on the shape of the load curvein so short a space of time.

12. Fuel costs for 1994 relate to the future generating system over the medium term. lbeycan thus be regarded as entirely reprsentative and used to measure the effects of the recommendadonsproposed for reducing losses in the medium term.

Anna fuel costs due to losses will be calculated for the following two cases:

Joule-effect ogses: the following assumptions will be made:

Peak power use: 5,900 hours;

Lad level depends on the shape of the national load duration curve (see Figure 1);

Hourly fuel costs are as shown in the STEG pricing study (April 1988).

Core losses in transfrmers: the following assumptions are made:

Use: 8,760 hours;

Hourly fuel costS are the same as above.

-71 - Annex 2Page 4 of 19

LOAD DURATION CURVE 1989

Peakpower : 771 MWMinimum power : 230 MWAverge power : 513 MW

FIGURE 1

800v v - _ C _ _ 3;:~~~~I IA.- I I_ I _ _ __I _ as70 I I I I 1- I IA SLL9 i It- I 5 ai L

nn~~~~~~ . . .: . ._ I I2 I - I a--- . . . . .T .

_~~~~~ . . . . . . . . .E . .600R n n .-1-]-a-1 2 1 I 2 I a I I LI__ I _ :I

w~~~~~~~~~~~~ - - - - 3 - - 1- - . . . _.

_ *- * t. g . * * _ ; ;1 I aI: a I- t :: I _ I I F a

P (MW) 400:_ * a a I a . . . .^ . . . . . . .*. E*_n

300 .....

200 . . . . . . . . . .

100 tit

0 I L

8 1000 2000 3000 4000 5000 6000 7000 8000

HO'WS

VALUES TAKEN INWOACCOUNT

Relative P POWERMMW Half-hours Hours150 770 3 1.5

142.7 732 245 124133.8 686 623 435.5123.8 635 1605 1238114.1 585 3093 2784.5104.8 538 3584 457694.4 484 2273 571384.2 432 3093 7259.575.7 388 2568 8543.566.7 342 227 8657

1 | 54.5 280 70 8692

-72- AM Page 5 of 19

Calculation o Fuel Cos Result from Jule-effect Losses

13. Joule-effect losses are proportional to the square of the load. The standard loss curve cantherefore be calculated from a curve derived as follows from the load duration curve: a time variationIn the ordinate is proportional to the square of such variations in the load duration curve (see curve inFig. 2).

The curve is divided Into three periods:

- a first period of 1,252 hours, corresponding to the peak;

- a second period of 4,223 hours, corresponding to the daytime hours;

=an ht period of a total duration of 9 h x 365 = 3,285 hours.

14. The annual Joule-effect for each of the above periods is determined on a chart byconstructing equivalent rectangles with a surface area equal to the areas subtended by the curverepresenting lost eergy.

The following results are obtained (see Fig. 2):

- 78% of the peak losses for the peak period;- 54 of the peak losses for the daytime period;- 32% of the peak losse for the night period.

Annal energy losses cofresponding to 1 kW of losses are therefore as follows:

- peak: 0.78 x 1,252 = 976 kWh;- daytime hours: 0.54 x 4,223 = 2,280 kWh;- night hours: 0.32 x 3,285 = 1,051 kWh;

The marginal costs in millines/kWh considered for 1994 are given in the April 1988STEG tariff study).

- peak: 38.2- daytime period: 30.3-nightperiod: 23.

The annual fael cost for 1 kW of peak losses will therefore be as follows:

(976 x 38.2) + (2,280 x 30.3) + (1,051 x 23) = 130,540 millimes = TD 130.

CALCLLATION OF ANNUAL FUEL-COSTS

1 X

0.9

0.P S hae of e boad

0.7 t \

0.6 - - hae Joub. cu~~~~~~~~~ecuv

%PEAKP 0.5-

0.4- -

0.3 - -

0.2 - -

0.1 -

O- I . | - I I -I -I'II $0 1000 2000 3000 4000 5000 6000 7000 8000 I.-

FIGURE2

-74- Annax 2Page 7 of 19

Mr.: Ihe cost calculated above relates to the power output level. At each point on the network, losseswill be calcuated for the corresponding supply network. The above calculation refers to the duration ofthe fbllowing peak power utilization: average load (see Fig. 2) is 513 MW. Thus, annual power oututIs:

513 x 8,760 = 4,493 GWh.

Peak power is 771 MW; the duration of peak power utilization is therefore:

4.493 x 10' = 5,828 hours771

The load factor P is as follows:Ppeak

0.66771

Caculaion of the Fuel Costs Resulting from Core Losses in tie Transformers

15. In this case, the load duration curve is horizontal. For IkW, power output levels perperiod are as follows:

- Peak: I kW x 1.252 h = 1,252 kWh- Dayme: 1 kW x 4.223 h = 4,223 kWh- Night: 1 kW x 3.285 h = 3,285 kV h

The anmual fuel cost at the power output level will therefore be as follows:

(1,252 x 38.2) + (4,223 x 30.3) + (3,285 x 23) = 251.3 x 103 millimes, = TD 251.

-75 AM 2Page 8 of 19

IHNREbf-b CT S IN 3ISTA

16. The purpose of this study is to propose values for the incremenl costs per kiowatt, sothat savis from loss reductions can be etmated. Most of these costs are taken from the Apri 1988STEG tariff study. Consequently, the financial data given below are expressed In 1989 Tunisian Dinrs.

Generating Costs

17. Ihe incremental cost for generating equipment is based on the insttalation cost of the 150-MW unit to be installed at Rades. The gross development cost is determined as follows (based on aninstlion cost of TD 673 per kw):

Depreciation (over 30 years): TD 22.41kWFinancial charges (10%): TD 67.3/kWFixed operang costs: 'ID SAlWkTotal TD 97.71kW

Fuel savings are calclated to be TD 41 per kW, which leads to a net incremental cost of TD 56.7 per$W, rounded to TD 57 perkW. Ihe number of kW installed per additional kW at the peak is 1.25 (seeSTEG load curve). The incremental cost is thus 57 x 1.25, i.e.: Incremental cost for generation: TD71 per kW.

-76 Annex 2Page 9 of 19

Iment B Co Hy TIanmi«ion

18. The investment program for transmission scheduled in the 1987-91 plan i TID 15 million,for a total of 117 km of lines. 'Te investment cost per kn of lines is TD 128,000. The technicalcomponents of the transmission program call for construction of 0.32 m of lines per additional installedkVA HVIMV and 1.825 installed kVA HV/MV per additional peak tW. Invertment in HV transmissionper additional peak kW is thus: 128 x 0.32 x 1.825, i.e., TD 75 per kW,

The incremental cost is therefore:

Deputiation (over 30 years): Ti) 2.5/kWFinancial charges (10%): TID 7.SkWFixed operating costs: TD 07.7/LdVTotal TID 10.7/kW

karet Cost f HV/KV Substations

19. The investment program for transmission scheduled in the 1987-91 plan is TID 21 million,for a volume of 363 MVA of installed capacity. The investment cost per instaled MVA is TD 57,500.The technical component of the transmission program call for construction of 1.825 insalled kVA1V/MV per additional peak kW. Investment in HV transmission per additional peak kW is thus 57.5x 1.825 ='TD 105/kW.

The incremental cost is therefore:

Depreciation (over 30 years): TD 3.5/kWFinancial charges (10%): TD 10.5/kWFixed operating costs: TD 0.9kWWTotal TD 14.9/kW

-77- AL2Page 10 of 19

20. GnzI: The total investment In distribution is given in the dir4tives of the distributionmaster plan for the 1987-91 period of the Vllth Plan.

Iglte AM: SUSARY OF INVESTIENTS IN NV SUBSTATIONS(thousand TO)

SgEG financing Third party financing Total

Rural investments 3.200 26,000 29,200urban investments 4.500 0 4 500Industrial Inestments 0 17,000 17,000Saitation invlecments 17,200 0 17,200

Total 24,900 43,000 67,900

21. a: The value of the MV marginal cost is equal to the ratio of total MVinvestment to the increase in MV peak power. The latter represents 86% of the increase in total power,i.e.:

Total peak power in 1987: 710 MWTotal peak power in 1991: 910 MWDifference: 200 MWDifference on MV network: 172 MW(ratio of 86% for MV and LV at peak power)

22. Total MV investment for the period is TD 67.9 million from all sources in the Tunisianeconomy, regardless of origin; STEG's investment is TD 24.9 million.

- This gives an incremeal cost (excluding losses, and considering only STEG'sinvestment):

Investment per additional peak kW:

24.900 = TD 144 per peak kW172

-78- Annex 2pop 11 of 19

Depreciation (over 30 years): TID 4.81kWFinancial charges (10%): TD 14.4/kWFixed opeting costs: TD 3.1kWIncremental cost TI) 22.2/kW

Thbis gives the following total incremental cost (excluding losse, ant includingall sources of investment):

Investment per additional peak kW:67,90 - TD 395/peak kW172

Depreciation (over 30 years): TD 13.2fkWFinancial charges (10%): TD 39.5/kWFixed operating expenses: TID 3.0nkwIncremental cost TD 55.71kW

23. Q:imI: The total investment in distribution is given in the directives of the distributi mnmtr plan for the 1987-91 period of the VlIth Plan.

Iable A2,J: SUNNARY OF INWESTMETS IN tN/LV SUBSTATIONS(thousand TD)

STEG Finanring Third Party Financgn Total

Rural intmmnts 1.000 6,300 7,300Urban nventments 7,000 0 7.000Industrfal Investments 0 0 0

(Cl. Ind.)Sanitation Investments 8,600 0 8,600

Total 16,600 6,300 22,900

24. hUrEe cost h Ie marginal cost of I MV/LV kW is equal to the ratio of totainvesten t the increase in LV peak power. The latter is equivalent to 48% of the Increase in totpower, i.e.:

-79- &nnZ 2Page 12 of 19

Total peak power in 1987: 710 MWTotal peak power In 1991: 910 MWDifference: 200 MWDifference for MV/LV substations: 96 MW

25. Total investment in MV/LV substations for the period is TID 22,900 million from allsources in the Tunisian economy, regardless of origin; STEG's investment is TD 16 million.

- This gives the following incremental cost (excluding losses, and consideringSTEG's investment only):

Investment per additional peak kW:

0§M = TD 173/peak kW96

Depreciation (over 30 years): TID 5.7/kWFinancial charges (10%): TD 17.3/kWFixed operating costs: IP 2./kW

acremental cost TD 25.0/kW

f investment from all sources is included:

-"2.90= 239/peak kW96

Depreciation (over 30 years): TD 8.0AWFinancial darges (10%): TD 23.9/kWFixed operating costs: m 2./LkWIncrementa cost TD 33.9/kW

iL,: The fixed operating costs for MV and LV were considered to be identical, in accordance with theSTEG tariff sudy; i.e., TID 6 per kW for all the MV/LV substations and the LV network. Dbutionof ID 2 per kW for MVILV substations and TD 4 per kW for the LV network were mumed.

Low Votgb" Network

26. Gnera: The volume of investment in disibution is given in the directives of thedistribution master plan for the 1987-91 period of the VIIth Plan.

-80- Am2Page 13 of 19

Tabtg a..: IAAY OF IWNESTMENTS IN LV SUBSTATIONS(thousand TO)

STEG Finaring Third Party Financing Total

Rurat invstments 2,800 23,700 26,S00Urban Investments 10,500 10,500 21,00IndLustriaL Investments 0 0 0Soitation Investments 17,200 0 17,200

Totat 30,SOO 34,200 64,700

27. In ol Cg: The margh cm of k LV kVA is equal to the rato of totalinvestment to the increase in LV peak power. The latter is equivalent to 48% of the increase in totalpower, i.e.:

Total peak power in 1987: 710 MWTotal peak power in 1991: 910 MWDifference: 200 MWDifference on LV network: 96 MW (200 MW x 48%)

28. Total low voltage investment for the period is TD 87.6 million (including nonSTEGfincing); STEG's investment i TID 47.1 million.

- -This gives the following incremental cost (excluding losses,, and consideringSTEG's investment only):

Investment per additional peak kW:

3020 = TD 318/peak kW96

Depreciation (ovcx 30 years): TID 10.3/kWFinancial charges (10%): TD 31.0/kWFixed opeating costs: M 4.0Q/lWIncremenal cost TD 46.4JkW

-81- AnnePage 14 of 19

This gives the following cremental cost (excluding ses, ad Includinginvestment from all sources):

Investment per additionl peak kW:

ft110 = TID 674/peak kW96

Depreciation (over 30 years): TID 22.41kWFincial charges (10%): TI 67.4/kWFixed operating expen: M 4CAlO.W.Incremental cost T) 33.9/kW

Su of mn

29. Ihus, the study leads to consideration of two scenarios, dependig on whether fundingconsists of STEG financing alone or financing from all sources.

Inrmna cm: Scenari 1

First scenario: STEG financing alone:

Incrementa cost of generton: TID 71.0/kWIncrementl cost of HV transmission: TD 10.7/kWIncremena cost of HV/MV substations: TD 14.9/kWIncremenl cost of MV distibution: TD 22.2/kWIncremental cost of MVILV substations: TD 25.0/kWIncremental cost of LV disibution: TD 46.6/kWin relation to the marginal peak kW)

The distributon of losses over the entire network Is approximaely as follows:

2.5% for the RV network2% fot the HV/MV transformers5% for the MV network3% for the MVALV transformers6% for the LV network

-82 -Page IS of 19

Calculadon of incremental cost per kW, taking upstream losses into account:

- HV network: (71 + 10.7) x 1.015 = TID 83.7/kW- HV/MV transformer: (83.7 + 14.9) x 1.02 = TD 100.6/kW- MV network: (100.6 + 22.2) x 1.05 = TD 128.9/kW- MV/LV transformers: (128.9 + 25) x 1.03 = TID 158.5/kW- LV network: (158.5 + 46.4) x 1.06 = TD 217.2ikW

RESULTS

NV/NV NV/LVHV Transformers MV Transformers LV

Incremntal costs . TD/k bi.7 100.6 128.9 158.5 217.2(includin tosses)

Irementl Costs: Scenario 2:

Second scenario: taking into consideration total investments (STEG and others):

Incrmental cost of generation: TD 71.0/kW3ncremental cost of HV transmission: TID 10.7/kW3ncremental cost of HV/MV substations: ID 14.9/kWIncremental cost of MV distribution: TD 55.7/kWIncremental cost of MVILV substations: TID 33.9/kWncremental cost of LV distribution: TID 93.8/kW

(in relation to the marginal peak kW)

The distribution of losses over the entire network is approximately as follows:2.5% for the HV network2% for the HV/MV transformers5% for the MV network3% for the MVALV transformers6% for the LV network

-83 - AM 2Page 16 of 19

Calcuation of incremental cost per kW, taking upsteam losses into acout:

- HV network: (71 + 10.7) x 1.025 TD 83.7BMW- HV/MV transformers: (83.7 + 14.9) x 1.02 = TD 100.61kW- MV network: (100.6 + 55.7) x 1.05 = TD 164.11kW- MVtLV transformers: (164.1 + 33.9) x 1.03 = TD 203.9/kW- LV network: (203.9 + 93.8) x 1.06 = TD 315.6&kW

RESJLTS

NV Nl/NV NV NVJLVTransformers Transformers LV

Incroentat cost in TD/ld 83.7 100.6 164.1 203.9 315.6(inctudIng Losses)

30. Ibis second scenaio will be used in calcat the cost of losses. In faCt, it is closewto act coss and akes Into accout al the power savings for the community. Generally, the margialcos method should inclu&a all costs, so that tariffs can reflect energy costs as accurately as possible.

31. As indicated above, the anmal cost of 1 kW of peak losses is calculated by adding theannal fuel costs (as a function of the load duration curve), the incremenal cost of genation equipment,and the incremental cost of the works upstream of the point selected.

The dibution of losses over the entire network is approximately as follows:

- HV network: 2.5%- HV/MV transformers: 2%- MV network: 5%- MVILV transformers: 3%- LV network: 6%

-84A Page 17 of 19

The following two cases will be examined: the general case, which follows the profileof the load duradon curve used in the calculation (about 5,900 hours of peak power use), and the caseof transforner core losses (8,760 hours of power use).

Ibe aoew

32. Calculation of the annual cost of one kW of peak losses. The incremental cost of oneadditional kW was given In a preceding paragraph. At this point, therefore, we need to calculate onlythe cous of fuel (including losses) at each level of the network:

- Generation: 'ID 130tkW (see above)- HV network: 130 x 1.025 = TID 133.2/kW- HV/MV transformers: 133.2 x 1.05 = TD 135.9/kW- MV network: 135.9 x 1.05 = TD 142.71kW- MVILV transformers: 142.7 x 1.03 = TD) 147/lW- LV network: 147 x 1.06 = TD 155.8/kW

Calculation of total costs:

- HV network: 83.7 + 133.2 = TD 216.9/kW- RV/MV transformers: 100.6 + 135.9 = ID 236.5/kW- MV network: 164.1 + 142.7 TID 306.8/kW- MV/LV transformers: 203.9 + 147 = TD 350.9/kW- LV network: 315.6 + 155.8 = TD 471.4/kW

We obtain the following table:

Table A4: ANNUAL COSt OF ONE KW OF PEAK LOSSES

Cost at this use levet (TDAIV)Arnual peak power use __,__

NV NV/NV NV VIVLVTransformers Transformers LV

5,900 hours 216.9 236.5 306.a 350.9 471.4

- 85 - Ame 2Page 18 of 19

The Cae ofTnufm Cm Lo=

33. The incremental costs of the investments were calculated previously. To these we willadd annual fuel costs (including losses) calculated for the network under consideration.

IMM I=,&=rme>. Calculation of amual fuel costs.

- Generation: TID 251/kW (see above)- HV network: 251 x 1.025 I TD 257.2/kW- HV/MV transformers: 257.2 x 1.02 - TD 262.4/kW

Total cost:

- HV networt: 83.71 + 257.1 = TD 340.9/kW- HV/MV transformers: 100.6 + ;62.4 - TD 363/kW

Calculation of annual fuel costs:

- MV network: 262.4 x 1.05 = TI 21 5.51kW- HV/MV transformers: 275.5 x 1.03 = TD 283.8/kW

Total cost:

- HV network.: 164.1 + 275.5 = TD 439.6/kW- HV/MV transformers: 203.9 + 283.8 = TD 487.7/kW

We obtain the following table:

tablLAZJ: TOTAL ANUL COST OF ONE KU OF CORE LOSSES IN THE TRANSFORMERS

cost at this use level (in TO/kM)AnnuAl peak powr use

MV/NV NV V/LVNV Transformers Transformers LV

8,760 hours (core tosses fraud transformers) 340.9 363 439.6 487.7

-86- A= 2Page 19 of 19

TI2t9 284.: ANUAL COST OF ONE KW OF PA LOSSES

Cost at this use leve (in tD/l)Amsl peak poet use

NV/V NV/LVHV Transformers NV Transformers LV

5,900 hours 216.9 236.5 306.8 350.9 471.48,760 hours (core losses from transformers) 340.9 363 439.6 487.7

- 87 -

Page 1 of I

EQUIVALENCE BKTWEN THE IMMETE RATE OF MAND THE ITERNALRATE OF PEFUR

Tb*t AM.: CONVERSION OF IMMEDIATE RATE OF RETURN INTO INTERNAL RATE OF RETURN

FPrmclal tRR IRR IRR Igopayback period Iniediate Duration: 10 years Duration: 20 years Duration 30 years

10 years 10 0 7.8 911 1.8 9 1012 3.5 10 11.613 5 11.5 12.614 6.6 12.7 13.715 8 14 14.816 9.6 15 15.817 11 16 16.818 12 17.2 17.919 13.7 18.4 18.9

S yearo 20 15.1 19.4 19.921 16.4 20.5 20.922 11.7 21.6 21.923 18.9 22.6 22.9524 20.2 23.4 2425 21.4 24.7 25

4 years 25 21.4 24.7 2530 27.3 29.8 30

3 years 35 33 34.9 3540 38.5 40 4045 43.8 45 45

2 years 50 49.1 5.0 50

, 2 years 55 54.3 55 5560 59.4 60 6065 64.6 65 6570 69.7 70 7075 75 75 75

Page 1 of 6

BEAT RATES OF THE STEAM THERMAL PLANTS

Sousse P oE Plant - Units 1 and 2

ouasl heat rates (1908)

10

9

B

7

6

5

4

3

2

2450 .2500 2501 2550 2551 2600 2601 2650 26S1 2700 2701 MO Ml 2800

i2niU

Annual heat rate data distributionKcaL/Kwh

2800

x

2700x

N2650

xx x x

2600

N25S0

N2500.x

2450

I I I I I I I I I11 J F N A N i J A S 0 N 0

NsM: X " 200 Kcat/ltmh Standard deviation: ; u 86.9

Reference value (for gs and at neminal load): 2565 Kcal/Kih

-89- AmPage 2 of 6

Sousse Power Plant - Unit 2

Annual host rate (1988)

10

9

8_

6

4

3.

2450 2500 2501 2550 2551 2600 2601 2650 2651 2700 2701 2750 27S1 2800

Arnal heat rate data distributionalCst/Kwh

anoo

2750

2700x

2650x

x x2600

x x

2550x

x x2500

2450

J F n A N J J A S 0 N D

Ne: ' * 2613 fctat/E Standard deviationt V * 71.4

Reference value (for ges and at roganal toad): 2565 Kcal/Kth

-90- AM0CAPage 3 of 6

Radbs Power Plant - Unit 1

Annual heat rate (1988)

10

8

6

5

4

3

2 _

2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650

Annual heat rate data distributionKoal/Kwh

2650

2550

2500

x2450

x x xx x x x xx

2400

2350_

2300

J p N A N J J A S 0 N D

un: 2428 Kcat/" Standard dewiation: Q .28

eference value (for gas and at nominal load): 2350 iIKet/uh

-91- Page 4 of 6

Radf Power Pla - Unit 2

Anwnul heat rate (19B8)

10

3

2

1 H-2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650

Anmuat heat rate data distributi onKceI/Kwh

2650 .. . . .. . .

2600

2550

2500

x x2450 .

x x xx x x x x

2400x

2350

2300

I II III I I I I IlJ F N A N J J A S 0 N D

Wean:u a 243? Kcal/KAh Standard d.vfation: u 17

Reference vlume (at nrmnal load): 2350 Kcat/Kwh

-92 A 4Page 5 of 6

Radbs Power Plant - Unit 1

AnmuaI heat rate (1989)

10

9_

7_

4

3

2_

F - _ ___ __

2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650

Arlat heat rate data distributionKcal/Kwh

2650

2600

2550

2500

2450x x x x x

x x2400

2350

2300

,IIIIIII I I I I IJ F N A N J J A S 0 N 0

Nean: It., 248 KCca/h Standard devfatfon: 7 a 13.4

Reference value (at nminal load): 2350 Kcat/Kwh

-93- AM 4Page 6 of 6

Radbs Plant - Unit 2

Anmuat heat rate (1989)

10

9

8

6

4

3

2_

2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650

Anual heat rate data distributionKcat/Kwh

2650

2600-..._...

2550

x2450

x x x x xx x x . x x x

2400

2350

2300

J F N A N J J A S 0 I 0

Me-n: t 2434 Kca1/Kih Standard deviation: ?F u 11.7

Refererice value (at nominal Load): 2350 Koal/Kwh

- 94 - AnnaPage 1 of 5

FFI CIENCY MONITORING

Monitorin Variations in Unit Heat Rates

1. The table on page 2 of this annex (Table AS.1) gives examples of variations in theopwaing parameters of a 115 MW unit (MONTEREAU) and of the magnitude of the corresponding

eases in heat rate.

al Excess Consumtion of Fuel due to one Additional kcal/lWh

2. 3Q MW Systm. For an annual utilization of 6,500 h, the energy generated will be:

6,500 x 30,000 = 195,000,000 kWh

Excess consumption of heat due to one additional kcal/kWh is 195,000,000 kcal. Forexample, if a fuel oil has a HHV of about 10,000 kcal/kg, excess annual consumption will be 19,500 kg(20 metric tons).

3. IfI MW m. On the same basis, excess fuel consumption will be:

6,500 x 160,000 104,000 kg (100 metric tons)10,000

4. Ihus, continuous monitoring of heat rme variations - and eliminaon of their causes -makes considerable fuel savings possible, especially in the case of units with a high unit capacity rating.

-95- MM zPage 2 of S

Table AS.1: SANPLE VARIATIONS IN OPERATING PARETERS AND THEIR EFFECTrON THE HEAT RATE OF A 125 NW SET

(FOR A BASIC OPTINU14 CONSUPTlION OF 2200 kcal/kIh)

Parameter causing 'NW1j the hvsic c -war - --- re -the variation COB Consurptton recorded In kcaL In X o BOC

Output P 125 NW 60 NW 85 3.8

Output O COS I COS 0 0.9 6 0.3

Cooling water 21.50C 13.5"C 25 1.14

Ambient air 26.5§C 16.54C 10 0.45

Condenser temerature 33.60C + 30C 10 0.45* Fouling* Air Intake

Sensible heat 5% 10% 22 1(Exes 02)

Superheated steam 124.5 bar - 10 bar 11 0.5pressure

Superheated steam 5400C - IOC 5 0.23teqerature

Resuperheated steam 5400C - 1OC 5 0.23teeperature

HP steam reheaters NS 43 2

LP steam reheaters HS 71 3.2

JEfficiecM Monitoring Methodology

S. The purpose of efficiency monitoring is to continually monitor fuel consumption per unitof power generated so that the causes of variations in the heat rate can be eliminad as quicldy aspossible.

Definitions

6. HIaRate: kcal/kWh. This is the amount of fuel (expressed in heating value) used toproduce 1 kWh.

^,Xal HOtRate = .' IbTis is the heat rate obtained under normal opeing condions

-96- AmixIPage 3 of S

- watt-hour meters; and- fuel flow meters.

QOtimm Rase Consumpton (OBC): Ibis is the theoretical heat rate of the plant whenall operating conditions are simultaneously at their optimum, i.e.:

- equipment in perfect condition;- unit contrui parameters at their rated values;- output at its rated level; and- zero reactve power (Cos phi = 1).

Dviations: This refers to the various variations in heat rate attributable to the differencesbetween the actual and optimum (OBC) values of the corresponding physical parameters.

Sg.: These variations are always positive or zero values (if not, the OBC should be recalculated).Some variations in heat rate are independent of one another (e.g., steam water losses, unit output, etc.),whereas others are interrelated (e.g., temperature of the exhaust gases, atmospheric conditions, etc.).For overall calculation of interdependent variations, the approximation method is applied to dependentvarations.

Ei = relative deviation in consumption from the OBCei = absolute deviation (in kcal/kWh)OBC = Optimum Base Consumption

ei = EixOBCx(l + c')

i-n i-n

With CAO Eeie ; giving I: CS = OBC + eIIt 1=2

CAO: cow=pduascePWddigunit)operadon

HR - OBC(I + }E1) + 52)-. + E)...( + R)BR -OBC+e1+e2+...+eL..+on

lwfirxiade in el M is obtie by deloplg te prod atnd disregading de Wm Z.

* 97 * AnnAPago 4 of S

Q&IWQD f Ho Boa D2iffienc«

7. lTe calculation of heat rat differences comprises the following three successive stages:

- processing of the data obtained for each load level (30MW and ISOMW);- calcuation of differences for each load level;- calculation of weighted average deviations.

PiM Pa mmnguIingjfa CdgW a timda . Ihe energy produced for eac load level idetermined as follows:

- by using the load diagram;- by using a meter calibrated for several tariff levels (the same number of tariff levels

as of load levels).

Cafl1atioD. of &Aye : Each month, arithmetical averages are calculd for eachopeating difference for a given load level.

&W.: The deviations are much easier to calculate if a set of nomograms i developed giving direct* readin of deviations corresponding to variations in physical quantites based on the OBC (see exmpleat the end of tds document). The deviations are classified a follows:

- externa deviations (due to conditions unrelated to plant opeation, such as the weather);- nteral deviations (due to equipment condition, unit control, etc.);- deviations resulting from a combinadon of the above.

ating MWd Al=gg Deyigi= Since deviations are calculated for each loadlevel, the average for each deviation is obtained by introducing a weighting to take account of the enrgenerated at each load level. By applying the correction term of the dependence relation to the relativevalues of the deviations, we obtain the absolute value for each deviation.

HEAT RATE VARIATIONS DUE TO SHUTOWN OF THE FEEDWATER SYSM

440

420

400

380

kJ/kWh

360

340

320

300 I _ l l0 50 100 150 200 250 300

Net Output (MW)

FIGURE 3

- in oq~~~~~~~~~~nlat

--

0n

4; i - 0 - - ,C #t 2'

0 B b W||B5 WEAr§'

44o .4tX W

1i -I L I I I I IX

-100-Page 2 of 8

3. The term "Measurements needed" means direcdy usable measurements that can be madeusing various sensors and calculation algorithms. A summary flow chart of the software is given on page4.

4. When a parameter deviates from the reference value that Indicates optimum efficiency,the computer in the control room displays in real time the amount of the deviation, the resulting increaseIn the heat rate, and the financial loss involved.

S. The continuous display of data related to the main unit managemement parameters thataffect efficiency enables appropriate correctve measures to be adopted at any time.

6. This application also makes it possible to carry out performance tests that enable operatorsto check the specifications guaranteed by the manufacturers, and to monitor changes in the performanceof the main components.

7. This aspect of continuous performance monitoring is especially important to mantenanceplanning (i.e., predictive maintenance).

8. With this application, predictive maintenance and operating efficiency can be considerablyimproved. However, it is difficult to quantify in advance the savings that will be obtained.

9. Installation of similar equipment for comparable power units has shown that one canexpect an overall heat rate saving of about 1% in the STEG steamn facilities, or an expected saving of:2MQ = 2.6 toe/GWh100

2.6 x 3,720 = 9,672 toe

260 toe/GWh = fuel consumption in 19883,720 GWh = thermal steam power generation in 1988.

A0essment of Coot

10. Because automated programs are already in operation (Radbs) or under study (La Goulette11), before introducing software for the on-line monitoring of operating efficiency, there should be a studymission to:

- evaluate the "efficiency monitoring' application that STEG is cfurently testing;

- 101 - Anext Page 3 of 8

ensure that it is compatible with software for the on-line monitodring of operatingefficiency;

aain what additional hardware is nesary and how long it will take to adaptit (study + on-site installation).

11. A preli inary cost evaluation for a power plant with two generating units breaks downas follows:

Table A6.2: COST ESTIMATE FOR INSTALLATION OF AN EFFICIENCYNONITORING SYSTEM FOR TWO UNITS

Cost (IS dottars)Unit cost Totat

Neasurement senors (10) s 2 16,500 33,000Neasurement lines (20) Y 2 16,500 33,000Data collection penels (40) x 2 10,000 20,000.Data collection software x 1 6,500 6,500Data processing software x 1 10,000 10,000Computer x 2 8,900 17,800Travel, trips, study costs 66,700

Subtotal 187,000

Contirngencies (11.5%) 21,505

Estimated Cost 208,505

12. Study costs comprise:

- 2 weeks on site to assess feasibility (2 specialists);

- 2 weeks abroad for project study and preparation (2 specialists);

- 4 wees on site to install and adjust the equipment and to train local staff (2 speciaists).

If any of STEG's existing hardwara is compatible with the project, a reassessment willbe needed.

-102- A1U§L"Page 4 of 8

Summary of the Software Flow Cht

Neasured powr DfrneLosu I doe to reduced load level

Condenser lnlet teperature characteristic curves _Loss 2 due to ext. temp. + theoretical vacu

Reactive power Characteristic curves Loss 3 due to alternator performance

Type of fuel used Characteristic curve/unit Loss 4 due to type of fuel used

Loss due to other causes Loss 5 due to other causes

Sum of losses I to 5 a EXTERMAL DEVIATIONS

Deviation fromMeasured vacuum theoretical vacuum and loss Loss 6 due to condenser

curve NW f(vacuum loss)

Devilation from theoreticatFeedwater outlet temperature t nperature obtaied l Loss 7 due to feedwater system

characteristic curve f(feedwater flow loss)

Pressure and temperature 2 curves Loss 8 due to steam characteristics

NP outlet pressure Deviation from P intake MP Loss 9 due to resuperheater load loss

P Calculation of the real andisentropic enthalpies, then Loss 10 due to MP housing

at UP inlet and outlet I comparison with a perfor- Imance curve f(P) l

-02 at economiser outlet Comparison with theoretical02 given by an 02 curve Loss 11 due to fuel coui,ustion regulation lf ' fuel used)

r Copearison of flows of de- Loss 12 due to excessive flow of superheatedfILowa of desuperheated steam superheated steam with steam

curves f(P)ll

rDeviation from amblent air||Tenperature at RA outlet h temperature and use of a Loss 13 due to performance

- - | ~~~GV performance curve dulopronm

02 In chimney stack Deviation from econamiser Indicates entry of air into reheaters02 measurement

Sum of losses 1 to 6 =SUI OF EXPLAINED INTERNAL DEVIATIONS

Reference power output - sum of tossesI to 13 a SUM OF UNEXPLAINED DEVIATIONS

-103- AnnexPage 5 of 8

TERMS OF REFERENCE

Supplyof an On-Line SBy for Monitoring the Operating Efficiencyof Fuel-Burninm lbermal Power Plas 21

Main Ob3ecive

13. STEG is inviting bids from consultants (corporations or public agencies) to design, supplyand Implement a system for the on-line monitoring of the operating efficiency of fuel-burning thermalpower plants.

14. This system will be adapted to match the hardware already available in each of the unitsand the efficiency monitoring software being tested by STEG. The objective of this system is to reducelosses in unit performance by continuous control room monitoring of the main parameters, to enableoperators to take corrective action in real time. This system also makes it possible to monitor thecondition of the main components and to undertake maintenance actions as part of a conditionalmaintenance strategy.

15. Ibis program consists of providing and installing a complete on-line operating efficiencymonitoring system for 150 MW units (in Sousse) and 30 MW units (in Gabes), taking existing equipmentinto consideration.

16. In particular, the project consists of the following components:

- a feasibility study to be conducted on-site;

- an additional study to be conducted outside of Tunisia;

- on-site installation of the system, which comprises:

. the computer;• the software;. data collection panels;. additional sensors and lines (if necessary)

21 In airstphs, dtes tnns of reference ptyp only to kWe Soe and Gab&splanu.

-104- APage 6 Of 8

- commisiornig of the equipment in the prence of STEG officis.

'he prject is estmat to require:

-6 man-week at the sites for the feaibflity study;

- 6 man-weelm outside Tunisia for project study and preparation;

- 16 man-weeks to nsa and adapt the equipment and to train local staff.

The total cost is estimated at P 2.07 million.

The project is finaced by ....

17. STEG is a commercial and industial stautory government entity established byNationalzaton Decree-Law No. 62-8 of April 3, 1962. This document makes STEG responsible for thegnaton, tra ion, distribution, import and export of electric power and fuel gas under thesupervision of the Miisty of the National Economy.

STEG has four steam power plants:

- Goulette U, with four 30-MW units consuming fuel oil;

- Ghannouch, with two 30-MW units consuming fuel oil or gas;

- Sousse, witi two 150-MW units consuming fuel oil or gas;

- Rades, with two 160-MW ailts consuming fuel oil or gas.

STEG also has 19 gas turbines with capacities ranging from 15 MW to 30 MW.

18. This prject, consistng of the installation of a system for the on-line monioring ofoperating efficiency, results from a recommendadon by the UNDP/World Bank mission fo improvingthe perform of STEG's power generation system.

19. The project includes all necessary resources for achieving the main objecdves defedabove. It wil be Implemented in the Sousse and Gabbs power plants.

-105 -M

Page 7 of 8

20. The sensing devices that are already installed and operating properly will be used to theextent possible. A data collection panel and appropriate software should be installed so that measurementsignals can be made compatible with computer data input.

21. About 24 major measurements - such as active power, steam characteristics, boilercharacteriics, etc. - will be used in the application. Curves and nomograms for calculaing deviationswill be established on the basis of commissioning tests. Convendonal hermodynamics equations will beused to calculate heat, consumption, losses, etc. The computer, to be itlled in the control room,should continuously indicate losses and their causes, in units of heat and in cost tem.

22. The contracting party wil be entirely responsible for project execution, and will provideall the services and equipment necessary for its proper implementation.

23. The bid should take the form of a turnkey project, to include computers, software,software interf , and Installation. However, STEG will be responsible for importg the equipmentand for proviing experienced technical and data processing specialists to monitor installation and assistwih wring.

STEG will be responsible for the following:

. access to the power plans and to the necessary data;

* consultant travel within Tunisia;

. providing instrument specialists and electrical equipment, as needed;

assistance in obtaining all administrative documents necessary to enable the contractor'spersonnel to enter Tunisia or to facilitate imports of equipment.

Qon Of tilel3id

24. The bid should include the following main elements:

- a work plan in line with the terms of reference;

- estimates of the time required, by specialty and by location;

- a description of the bidder and of its experience in similar projects;

Page 8 of 8

- the personnel to be assigped to the project, with complete rdsumds and accounts ofpreious experience.

25. Bids must state the total prlce, and be sealed.

Nevertless, bidders may suggest alterate methods of achieving the objectives statedIn the tems of reference. Any alternative method must be clearly defined and should be submitted asa separate bid with iemized costs.

26. The payment schedule will be subject to negotiation.

The bidder must propose a schedule that takes into account the performance objectives.

27. - 3 weeks on site t assess feasibility (2 specialists);

-3 weels abroad for project study and preparation (2 specialists);

-8 weeks on site to install and adjust the equipment and to train local staff (2 specialists).

-107 - Anum 7Page I of 2

UNAVAILABILITY RATES AND AVAILABILITY STATITCSFOR CONVENONAL THERMAL POWER UNITS IQ/

1. The UNIPEDE/CME Mixed Committee described in the document "Availability andUnavailability Rates in Thermal Power Plants - Definitions and Methods of Calculation,* published i1977, the typical unit sizes recommended for use in thermal power plants. The unavailability rate overa specified period is defined as the ratio of the energy that a capacity equal to the unavailable capacitycould have produced during this period to the energy that the maximum capacity could have producedduring the same period. The unavailable capacity is the difference between the maximum capitypossible (with all equipment supposed to be running properly) and the available capacity (maximumcapacity at which the station can be operated under actual equipment conditions).

2. The overall unavailability rate is designated as G and is divided into unavailability ratedue to planned maintenance, G1, and unavailability rate for all other reasons, G2 (G1 + 02 6). Theavailability rate (ratio of the energy that the available capacity could have produced over a given periodto the energy that the maximum capacity could have produced) is the difference between 1 and the overallunavailability rate G.

3. The conventional thermal units have been divided according to their unit capacity andtheir geographical location.

Annual unavailabilitv rates for the years 1981 through 1985

4. The unavailability rates shown in the following table (Table A7.1) distinguish betweenunavailability due to maintenance work and unavailability for all other reasons (unplanned unavailability).

The sum of the two rates represents the overall unavailability rate.

5. The results show that, for a given capacity range per set, unavailability rates are similarin Europe and in the United States. The unavailability rates for other countries are notably different dtmthose calculated for Europe and the United States. The difference is significant in the 100-199 MW unitcapacity category, where the overall unavailability rate for the other countries is on average some 6%higher than in Europe and the United States. Overall unavailability rates for a unit capacity of 100-199MW are calculated as: 19% in Europe and the US; 25% in other countries.

lQ, Sowrce: UNIPEDElWorld EniuV Coference.

108- An .Page 2 of 2

rabls A7.1: CONVENTIONAL 100-199 NW THE2"AL UNITSANNUAL UNAVAILABILITY RATES IN X

Year Europe United States Other countries

A TA A T

1981 49,260 399 53,91? 380 11,482 771982 48,400 393 57 aM 412 11.785 801963 47,792 386 57,343 407 13,008 901984 47,435 380 56,678 401 13,158 911985 29,764 237 8,497 55

G1 G2 0 GI 02 a G1 02 a

1981 11.4 8.8 20.2 10.7 8.2 18.9 11.9 10.6 22.51982 11.6 8.0 19.6 11.9 7.2 19.1 13.0 10.6 23.61983 10.7 7.8 18.5 11.7 6.9 18.6 17.1 10.6 27.71984 9.6 7.3 16.9 11.6 5.9 17.5 13.5 10.8 24.31985 10.4 7.5 17.9 12.7 12.3 25.0

Average 10.8 7.9 18.7 11.5 7.0 18.5 13.8 10.9 24.7

Number of sets on January 1 a T.Average maximum capacity of the units on January 1 a A (in NW).Unavalabi ilty rate: G1 = annual maintenance program; 02 a all other causes;a a the sum of the two.

-109- AnePage 1 of 3

SrANDARD MAUNTENANCE CONCEPIS

Maintenance Those activities necessary for enabling a machine to be maintained in - orrestored to - a specific condition, or to fulfill a certain purpose.

Maintenance performed after the appearance of a malfunction.Maintenance It includes:

- Detection The identification of a malfunction or a malfunctioning component as a result ofclose inspection, whether continuous or periodic.

- Location The identification of the specific components causing the malfunction.

- Diagnosis The identification of the probable cause of the malfunction, using logicaldeduction based on a set of data. Diagnosis makes it possible to confim, addto or modify hypotheses regarding the origins and causes of malfunctions, andto specify what corrective maintenance operations are necessary.

- Emergency Action taken on out-of-service equipment to get it back into workingservice order, at least temporarily. Considering this objective, the results obtained can

be temporary and the normal regulations governing procedures, costs and qualitycan be disregarded. In such a case, repair will follow.

- Repair Thorough and specifically targeted corrective maintenance in response to amalfunction.

Maintenance performed according to predetermined criteria to reduce theMaintenance likelihood of equipment malfunction, with its consequent impact on the services

provided. There are two types of preventive maintenance:

RtOWIe Maintenance performed according to a schedule based on time intervals or onactual equipment use.

Mainteanc

Cnditional Maintenance contingent upon certain predetermined events (self-diagnosis, sensordata, measirements of wear, etc.), indicating the degree of deterioration of the

W=anc equipment.

- 110- AnnaPage 2 of 3

Preventive maintnan comprises the following operations:

- lspecdon Examinations performed as part of a specific function. It is not necessailylimited to a compsrison with pre-established data, and the characteristic methodused is that of inspection "rounds."

- Monitoring Ascertaining that equipment complies with pre-established data, at which pointa judgment is made as to its condition. Monitoring can:

. include data collection;

. include a decision (acceptance, rejection or postponement of maintenance);

. lead to initiation of corrective actions.

- Maintenance A detailed and predefined examination of all or part of the various componentsExamination of the equipment (depending on whether the examination is general or specific).

It may include first-level maintenance operations.

Some corrective maintenance operations may be performed if anomalies areobserved during the maintenance examination.

- Test An operation enabling a system's responses to an appropriate and predeterminedstmulus to be compared to those of a reference system or with a physicalphenomenon that indicates it is operating correctly.

In addition to the actions defined above, maintenance also includes certain typical operations that are notsystematically included in any one type of maintenance. They are:

- Overhauls Eaminaons, monitoring and action for protecting equipment from any majoror critical malfunction for a given time or for a given effective period of use.Depending on the scope of the operation, it is usual to distinguish between partialand general overhaus. In both cases, this operation involves removing varioussubunits. This distinguishes overhauls from maintenance examinations.

An overhaul can be either a preventive or a corrective maintnce operation,depending on whether it is performed in response to a maintenaue schedule, ameasur ent of wear, or a malfimction.

- Modifications Operatio of a definitive nature performed on equipment to improve itsoperation or to change its characteristics.

- 111 - &M aPag 3 of 3

- Standard Replacement of a component, assembly or subunit with anExchange Identical new or reconditioned item, in accordance with the manucr

specifications.

Finally, there are two standard maintenance operations concepts - renovation and rebuilding - at areclosely related to manufacturing and are often performned by manufacturers. Consequently, they arbeyond the scope of the maintenance carried out within power plants.

AnnmL2

-112- Page 1 of 4

LOAD FLW CALCULATIONS - Y OF R

Table A9.1: IODES: ACTIVE AND REACTIVE POWER

Plant Rated kV F Q 2 -P 3F P 1 4 a

Radeos 150 0 0 0 0 0 0 0 0Rados 225 0 0 0 0 0 0 0 0Tunis South 90 60 19 62 52 43 23 64 21Tunis North 90 25 13 41 24 25 1 27 14Tunis West 90 47 12 41 34 21 16 50 13Mnita 90 0 0 0 0 0 0 0 0Mn la 225 0 0 0 0 0 0 0 0M. Jemit 90 16 9 13 10 8 5 17 10Hamnamet 90 0 0 0 0 0 0 0 0HaNmet 1SO 23 14 24 12 17 4 25 15Enfidha 150 20 11 17 12 7 5 21 12Ta eroulne 90 39 19 26 23 15 2 42 21Ta erouine 150 0 0 0 0 0 0 0 0Ta rculne 225 0 0 0 0 0 0 0 0Aroussia 90 0 0 0 0 0 0 0 0M. sourguTba 90 40 13 22 14 32 13 42 14Oued Zargua 90 10 5 8 5 6 2 11 6Fernana 90 0 0 0 0 0 0 0 0iendouba 90 15 6 12 7 8 4 16 7Nebeur 90 0 0 0 0 0 0 0 014saken 150 40 11 31 26 18 11 42 12Akouda 150 25 14 26 13 15 2 27 15Mason 90 0 0 0 0 0 0 0 0Nasen 90 0 0 0 0 0 0 0 0Nasen 225 0 0 0 0 0 0 0 0Oueslatia 225 12 6 7 2 5 2 13 7M. Mchergua 225 16 7 24 15 10 0 17 8Sousse 150 15 6 12 6 12 3 16 7Sousse 225 0 0 0 0 0 0 0 0Grmbtalia 90 12 7 22 16 14 8 13 8Korba 90 23 12 11 13 7 2 25 13Tunis Center 90 10 5 10 8 2 8 11 6Tunis Center 90 t1 6 10 8 5 5 )2 7La Goulette 90 30 17 19 12 11 4 32 18Zahrouni 90 21 11 16 12 15 9 22 12Mdhl a 150 13 8 9 2 3 2 14 9Mettocuf 150 41 17 30 19 21 8 43 18Kasserine Nord 150 0 0 0 0 0 0 0 0Kasserine 150 19 9 11 7 14 5 20 10Naknassy 150 8 3 6 3 7 4 9 4Foriana 150 3 1 3 1 3 1 4 2Sfax 150 49 22 '6 31 21 10 52 24souchema 150 S 0 0 0 0 0 0Bouch_a 225 0 0 0 0 0 0 0 0Robbana 150 25 11 14 3 10 2 27 12Zarzis 1S0 I5 7 6 1 5 2 16 8Ghannouch 150 43 21 34 45 20 27 46 23S. Monsour 150 17 7 13 2 7 2 17 8S. Mansour 225 0 0 0 0 0 0 0 0S. Salei 90 0 0 0 0 0 0 0 0KItairouan 225 7 2 8 4 6 1 8 3Noknfne 150 13 5 22 12 10 3 14 6Mateuw 90 7 3 0 0 0 0 8 4Taborka 90 6 2 0 0 0 0 7 3Gomwart 90 5 1 0 0 0 0 6 2

ALGERIAN BORDER NODESElkala 90Aou1net 90Aouinet 22SDJebl 0k* 150

S urce: STEC, DEX, OPIME, various studies.

(1) Evening peak (Decalber 1989) Total load: 780 NM 342 NVAR (tg phf a 0.438)(2) Morning peak CSeptenier 6, 1989) Total toad: 646 NM 4S4 NVAR (tg phi a 0.703)(3) Valley CSepteuier 1969) Totat load: 420 NW 196 MNAR (tg phi f 0.467)(4) Future netuork Decerber 1990) Total toad: 836 NM 382 MVAR

£uiinnt: Data includ, the capcItors and the reactors.

TL* A.2: GEMATINB SET DATA

Year Cons. cans.brought of Aux. of Aux. cose w1 Case M2 s (32

Turbine Alternator into Turbine nianl Equip. Equip. P. win Cmnwection P P PPlant Nanufacturer wanufacturer service ips cos phi (HU) (MM) (M) nods

Rados al1 MITStISHI MITSURISII 1965 0.8 8 20 40 Rados 145 0 0odts. 1R2 MITSUBISNI NITStBISII 1985 0.8 8 20 40 Rados 140 140 130

Saiuss SR11 KW no 1980 0.8 7 15 40 Souse 120 120 90Soisse 612 KM 1 KU 1980 0.8 7 15 40 Sousse 120 120 90Goulette SR1 CEN C 1965 0.8 2 3 7 Goulette 20 23 15Goulette GR2 CEN CEN 1965 0.8 2 3 7 Goulette 20 23 15Goulette CR3 AEG AEG 1968 0.8 2 3 7 Goulette 0 20 15Goulette GR4 AEG AEG 1968 0.8 2 3 7 Goulette 0 0 0K. Ilorth t1G FIAT ALSTHTM 1984 0.8 1 1 10 K. Nord 30 30 0K.L orth 102 FIAT FIAT 198U 0.8 I 1 10 K. %rd 0 0 0Korbe TGI ALSITHON ALSiHITI 1978 0.8 0.8 0.6 5 Korbe 0 0 0KOrb0 T42 FIAT ALSJTIM 1984 0.8 1 1 10 Korba 0 0 0Rd*dne TGI FIAT ALSUHI 1984 0.8 1 1 5 Robbn 0 0 0Ghamrauch TOI ALSHTHC ALSNTHM4 1971 0.8 0.8 0.6 Ghanrmich 0 0 0Ghanmouch TG2 ALSUTHTI ALSITUOM 1973 0.8 0.8 0.6 6 Ghannouch 0 0 0banwmuch 1T3 ALSWTIII ALSIUM 1973 0.8 0.8 0.6 6 Ghann_ch 17 16 15

ShaGiouch 764 FlAT ALSNTHC" 1973 0.8 1 1 10 Ghanmoch 30 30 20Ohaiouch TVI CEm CEN 1972 0.9 2 3 11 6hard 28 28 20Ghawuch TYZ CEl CEm 1972 0.9 2 3 11 Ghanouch 27 27 20T. South T61 ALSHTMCN ALSTMlt 1975 0.8 0.8 0.6 5 T. Sud 20 0 0T. South T02 ALSHTNM ALSHTI1M 1975 0.8 0.8 0.6 5 r.Sud 0 0 0T. South TG3 ALS0THNN ALSHTHWS 1978 0.8 0.8 0.6 5 T. Sutd 20 20 0Bouchnm_ T6I FIAT FIAT 1977 0.8 1 1 10 Bouch_iwi 25 25 0Bouchwmm T02 FIAT FIAT 1977 0.8 1 1 10 Soum 0 0 0N. 3ourguibe TG1 ALSHTUCR ALSHTUGI 1978 0.8 0.8 0.6 5 N. Bourguibe 0 0 0N. ourguiba TGZ ALSHTH0N ALSNTH 1978 0.8 0.8 0.6 5 M. Buraiba 0 0 0Sfax TGI ALSHTHUI ALSITrEDI 1977 0.8 0.8 0.6 5 Sfax 0 0 0Sfax T02 ALSHTH ALSRTHN 1977 0.8 0.8 0.6 5 Sfax 0 0 0Nleoul TG ALSHTIIUI ALSKTUO 1978 0.8 0.8 0.6 S Metlsou 0 0 0Fernae CH 1958 0.8 0.5 0.2 0 FeMnna 5 5 aS. Salem Go 1982 0.9 2 3 0 S. Satem 25 25 0Nebsur GHI 1956 0.8 0.2 0.2 0 Mor 4 4 0Nbeur GN2 1956 0.8 0.2 0.2 0 ebobr 4 4 0

Sou STEGM, DiD, DPIE, varisos studies.

(1) Evening pek (Dece - r 1989) Total petien: 800 1M(2) fInfnt peek (Septeober 1989) Total prodfetaon: 660 NW(3) Eveninr troush (Septeoar 1989) Total production: 430 VW

I4I

-114--Page 3 of 4

Da on the Existina ReactorCsi8

nsaled Reactors in ngh eation Total genati in service

- on the Oueslatia-Bouchema feeder : 20 Mvar- on the Robann hannouch feeder : 6 Mvar(not equipped with a breaker) Night: -58 Mvar (reactors only)

- on the Maknassy-Ghannouch feeder : 6 Mvar- on the Tajerouine-Oueslatia feeder : 20 Mvar- on the Mdhila-Maknassy feeder : 6 Mvar

Caacitors Insalled (on the 30 kV MV busbars)in ervice durina the day

* to Menzel Bourguiba : 9.6 Mvar-to Tunis Ouest : 8.4 Mvar- to Tunis Sud : 8.4 Mvar Day: + 40Mvar(capacitorsandreactor-to M'saken : 9.6 Mvar Ghannouch)- to Medaoui : 9.6 Mvar

A Imi e VoljW I&.*

lable A9.3: UMN0 A 10X

Vottage (kV) N n. uax.

90 81 99150 135 165225 202 247

115 - 1Aim2Page 4 et 4

Table A9.64 GEIIEtATING UNITS EXPECTED TO BE IN OPERATION IN 1993IN ADDITION TO THOSE IN SERVICE IN 1989

Sets Norning peak Evening peak Evening trauoh

Netlaoul IGT X XSfax 2GT X XW. ourwulbe 20T x XRobbae lGT X XKlob 2GT X XLa Goulette 2ST I get 2 SetsSouchem IGT XKessarine North 1OT XTunis South 2GT X

ou8se 2ST X

Mgo: OT a gas turbine; ST * steam turbine.

tIM.-AIlM: LOSSES IN STEG'S IV IETWMK OgLY(excludiIg losses on tbo intterC0eCti on with Algeria)

Evening peak

Without Wi th existing Wf th Without cwftr ?m o calpnsatian capreacitors adci torsL cameration wi thout Wi th Uithout With

Cotilpensetion O 40 130 O0 211 O 211

Vottage: 2351cV 1.26 1.23 1.19 1.9 1.8 0.8 0.7225 kV 1.28 1.26 1.23 1.8 2.0 1.9 0.8 0.8 0210 kV 1.30 1.11.26 2.3 1 2.1 0.9 0.90

Tan phi 0.489 0.438 0.278 0.489 0.489 0.278 0.438 0.278 ADand 780 MW = 1000 NW _ Z

Generating Stem turbines 620 NWequip 64#~~~~G turbines 140 M1 218S CAP 80" CT in service hypotheses Hydropower 40 MW Contribution P = 224 NW P a 200 MW

from Atgeria I_Exports to 10 W 0 NW 5 NW 12 I3Algeria _s____ _

table A10.2: LOSSES IN X 11 STIE1S NV IETM GMLT(EXCludirg tossE on the intercomwtion with Alteria)

brning pk

1969 1993

c_pacitors Capa_.t_with existing With

Without capacitors emitfonat Without lithout with Without With.______ _ cc sation and reactors camcitors consation

Ca_pensation 0 40 130 0 0 211 0 211( KYAR) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Voltage: 235 kV 1.13 1.05 0.94 1.4 1.2 0.8 0.7225 kV 1.15 1.05 0.96 2.2 1.5 1.2 0.8 0.8

210 IkV 1.21 1.11 1.02 1.6 1.4 0.8 0.8

Tan phi 0.764 0.703 0.501 0.7 64 0.703 0.764 0.703Dem _d -_, 646 KW 829 mV

Generating Gas turbines : 500 mmequipment .as turbines : 120 mm CAP BON CT in servicehypothesis Hyropower : 40 M P = 224 15U P 200NU

Exports to 7N 0NM 40OW 22 1WALgeria - -

IL>

Table -10.3: LOSSS IN X ON1 $lU'S N TIEK OLTtEnd:fir tilosmes an the intercometion with Algeri)

Night troa*

19" ~~~~~~~~1993

Without With existing Uithout Without Wfithoutcoat! §on r reactors ractors reactors

Coepenation 0 0 0 0(WAR) . ._...

Vottage: 235 kV 0.95 0.90 1.0 0.9225 kV 0.98 0.90 1.0 1.1 1.0210 kcy 1.24 1.09 1.3 1.1

Tan vhi 0.328 0.467 0.328 0.328 0.328Thermal _utout 420 HU 542 NW __

Generating Gas turbines : 395 NW 117 W oequipment Gas turbines : 35 Wi Contribu- CAP SwO ST in sermicehypotheses ydropoer : 0 NW tion from p tt2 NW p = 125 NW

Alteria _Exports to 6 HU 3N8 O NM Rports of 7 NWAlgeirfe

A l ri o _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ~ ~ ~ ~ ~ ~ ~

ILt

I'~~~~~~~~~~~~C.0

0 t

a |~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~a

li; ! L 5'a- r -i a. a. § X 5 3

- 120 - Am 1IPage 2 of 4

TIlte All2: CONPENSATION REQUIRED BY SUBSTATIONTO BRING TAN PHI BACK TO 0.5

September 89orning peakconsu_tfa n Existing Capacitors

capacitors requ red to reduceSubstatIons Nu NVAR QI NVAR tan phi to 0.5

Tunis South 62 52 8.4 21

Tunis West 41 34 8.4 14

N. Jemil 13 10 3

TaJeroulne 26 23 10

N. sourguiba 22 14 9.6 3

N. %aken 31 26 9.6 11

Grombealia 22 16 5

Korba 11 13 7

Tunis Center 1 10 8 3

Tunis Center 2 10 8 3

Zahronil 16 12 4

Netleoul 30 19 9.6 4

Kasserrne 11 7 9.6 4

Sfax 36 11 13

Ghannouch i 34 45 28

Total 45.6 130In service from

7 a.m. to 11 p.m.

TheTsm values take into account the existing capacitors and reactors.

ki Currently, one 6 NYAR reactor on the oharnouch-Robbana feeder Is in service 24 hoursa day, as it does not have a breaker.

Table A11.3: NEASURING THE EFFECT OF THE PROPOSED ADDITIONAL CONPENSATION

.Evening Deak | Norno oeDk Night trough

Additfo- Additio-No Capacitor nl No Caoac. + nal With

capacitor + capaeftor capa- existing capac- 0 reactor existingexisting (0 citor reactors tor reastorsreactors reactor) (0

_49 048 7" 0- rea ctrtor)

Tan phi 0.489 0.438 0.278 0.764 0.703 0.501 0.328 O.U67

-121 - AnnexL11Page 3 of 4

THE NETWORK IN 1989

I 4r~~~~~~~~~~-3v I I7

t S.t u f w It %M

0~~t 60% Lo uo xsig caaios

I.~~eatr Iufnl in seKice_ G t g \s 62oFGURE 4 )

-122 - Awnx i1tPage 4 of 4

THE NETWORK BY 1993

FG St %AAF '8

t,aJ_~~~~~~~~~~~~~~~~~~~~sl Tn l s_ _ _ F 1^u>: / 1 lAt~~~~~~~~~~~~~~*:4

""f "e ~IqU 5-

- 123 - A 12Page 1 of 4

ECONOMIC ANALYSIS OF COMPENSATION

1. This economic study is a fairly summary calculation of the gains that could result fromcomp~nsatlng for reactive energy. There is a twofold benefit, technical and economic, in compesatingfor part of the reactive energy absorbed by the loads.

(a) The technical beneft has already been mentioned: introducing compensation incresuesthe network's operating margins, making operations easier and more reliable by reducingthe scope for voltage instability.

(b) Compensation also offers a significant economic benefit by reducing losses on thenetwork as a whole.

2. The purpose of this annex is to calculate the economic gains. The simulations madeInvolved calclatng the number of capacitors to be insiled to improve the load factor, as "seen" fromthe VHV transmission network substations. The relevant numbers of capacitors must then be allocatedamong these substations and those on the lower voltage networks that they supply (HV and MV). Inparticular, they should be installed in MV substations as close as possible to the demand so as to securethe malmum reduction in losses on these MV networks.

I calculafio

3. At peak hours, active losses on the network, in relation to the power supplied, areregularly reported to be around:

- 2.5% on VHV and HV networks

- 2% in HV/MV ransformers

- 5% on the MV network

- 3% in MVALV transformers

- 6% on the LV network

4. On the MV and HV networks, where the capacitors will prefrably be installed, peak hourlossa are generally 3 to 4 times greater than on the VHV network.

. 124 - Annex12Page 2 of 4

S. We have shown that the installation of capacitors "seen" from the VHV transmissionnetwork would reduce active losses on this network (Annex 9). The same is true for MV and LVnetwork losses when capacitors are connected on these networks. It should, however, be noted that,given the small size of the capacitor banks to be installed on the MV network and other ;onstrainvolved, in pardcular the space available in the substations, Installing capacitors on the MV network willnot necesarily be optimal. The capacitor banks will be grouped and installed in the substaions to theextent possible, producing a useful but not necessarily optimal reduction in MV losses.

6. Consequently, If the active losses on the MV and HV networks are 3 to 4 times higherthan on the tranmission network, the reduction in these losses through the use of "non-optimal" masof compensation will not be as large. We will arbitrarily reduce the ratio in question to 2 In order alsoto take account of the fact that only 86%, rather than 100%, of the power supplied to consumers passesthrough the MV network, and that there are losses in the transmission of reactive energy between thevarious voltage levels (VHIV-HV-MV).

7. To quantify the reduction in losses resulting from compensation we will use the costhypotheses fom Annex 2.

ANNUAL COST Of I kW OF PEAK LO LOSSES(Hours of Use: S,900)

L:L NV IV/NV NV NV/LV LV

C ost in TDOW 216.9 |236.5 |306.8 350.9 4U1.4

8. The aim is to examine the benefit to be gained from installing compensation resourceson the transmission network and the MV networks. This requires a base compensation cost, i.e., banksof capacitors and reactors, of TD 10,000/Mvar, entailing annual investment costs of TD 1,000/Mvar.

Operation of the Ghanmouch ractr

9. All the reactors are disconnected 16 hours a day. The Ghaninouch reactor (6 Mvar),which is pemanently connected to the network, is therefore in service for 16 hours too many each day,or during the 5,840 heaviest loaded hours of the year. The additional losses that this entails for thenetwork (in addition to the internal losses due to its resistance) can be calculated as follows:

- 125 - Annex12Page 3 of 4

10. The simulations showed that 170 Mvar of compensation produced a gain of 1,2 MW(morning peak) and 0.4 MW (evening peak), or 0.8 MW on average. The annual gain can therefore beobtned from:

6 Mvar x 0.8 MW x TID 216,900/MW = TD 6,120170 Mvar

The cost of a breaker being estimated at 0.25 x TID 10, it does not seem ecWnomicallyjustified to attach a breake to the reactor.

InsaWlation of gcapaitrs on the tranmissionetsgod5

11. Using the same procedure as above produces a gain per Mvar of:

) 216.90l/MW x 0.8 MW a TD 1 x 103/Mvar170 Mvar

or exactly the annual cost of installing compensation. Consequently, at the level of precision of ourcalcuations, It is, economically speaking, immaterial whether or not capacitors are installed on the HVnetwork. Only the advantages of increased network reliability in relation to a voltage collapse wouldjustify installing capacitors at this voltage level.

Intllaion of capac idosa the MV leVel

12. The preceding arguments only apply, of course, to the capacitors that would be installedin the VHV/HV or VHV/MV substations, in other words to the capacitors "seen" directly from VH.VThe number of capacitors required to make tan ph equal to 0.5 (170 Mvar in 1989 and 218 Mvar in1993) must clearly be allocaed over the entire network (VHV, HV, MV). From a technical andeconomic point of view it is more beneficial to install them close to the demand.

13. Installation of capacitors on MV would reduce losses not only on the VHV and HVnetworks, but also on the MV networks, and in much greater proportions. This ratio was put at 2 (seepara. 6 of this annex), which leads to a gain per Mvar of:

0.8 MW x 2 x 306.800 TDIMW = 2.9 X 10' TD/Mvar170 Mvar

a figure that suggests an internal rate of return for the investment of about 30%.

-126 - Annex1ZPage 4 of 4

Conclusion of tdh econo study on the Is__tinof comesan

14. This brief study has shown that It would be economically justifiable, in order to reducenetwork losses, to install capacitors. These should be placed as close to the load as possible, In otherwords, preferably on the MV network.

15. Tbis study is only a first approximation of the expected orders of mgnitude of thebenefits. It used a minimum nunber of network operating hypotheses and assumed that the gains achievedwere a linear function of the numbers of capacitors installed. These gains could thus only be calculatedby using two extreme hypotheses: no compensation, and compensation producing a tan phi of loads equalto 0.5. In practice, the gains are a parabolic function of the compensation. To obtain a more accurateidea of their magnitude, one would need to undertake a more precise analysis, incorporating a largernumber of hypotheses to permit better modeling of the load curve, and to calculate actual network lossesfor each load level considered, rather than accepting a global evaluation that assumes that these lossesare merely proportional to the square of the energy consumed. It is also necessary to calculate theselosses for more realistic installations of capacitors, taking local conditions into account (space in thesubstations, minimal size of each capacitor), and evaluate more precisely, either using statistical surveysor by making calculations for "representative' networks, the losses on the MV and RV networks and theImpact on these of a "realistic" installation of capacitors in the MV and HV substations.

16. This would reveal that the marginal gain (gain per Mvar Installed) declines as a funcdonof the overall amount of compensaion. Knowledge of these "marginal gains" would enable optimum useto be made of the funds tha may be allocated for reactive energy compensation.

- 127 -Am13

Page 1 of 1S

SELECON OF NETWORK SAPLE

Peseton of Disribution

Qeneral descripion of the network

1. The STEG distribution network operates at four voltage levels:

30 kV, 15 kV and 10 kV in the medium voltage range (MV);

400 V1230 V in the low voltage range (V).

2. The Distribution Direcoorate receives energy from the transmission network hroug41 master stations with primary voltages of 225 kV, 150 kV and 90 kV.

3. The MV network has a radial structure and consists of:

13,000 km of three-phase overhead lines, and 4,000 km of single-phae spurs at 17.3kV. The neutral of the three-phase overhead network is distributed and grounded; itis therefore a 'four-wireu system.

1,000 km of mostly underground 10-kV network supplying cities in the north likeTunis and Bizerte.

- 354 km of 15-kV lk>.s supplying large towns in the south: Gab0s, Gafa.

4. The tot length of the MV network is 18,400 km, 1500 km of which is undergund.This MV network supplies power to 30,600 km of LV lines (97% of which are overhead) through17,000 MV/LV transforming substations, 6,700 of which are customer substations. Following amajor campaign to change voltage levels, 98% of these MV/LV substations supply a secondaryvoltage of 400 V. Of the MV/LV substations providing a 230 V secondary voltage, 70% areconceatd in the Tunis region, particularly in the Tunis City distict.

5. The following tables give a breakdown by district of the MV and LV networks andthe MVALV substations. I

- 128 -Page 2 of 1S

TabIe A13.1: 1V/LV DISTRtWPTION NETWORK (1988)

futro substat1on Network beIgMth ib )

Districts T Prvate u vottTotat ~~~~~~~Low

LI L2 B1 B Tono- Tr- Total vottageI~~ _ I phase_ _pes __

Tunis Cfty 168 259 37 497 961 454 454 753Arinam 383 . 245 628 458 458 1020Exahra 9 346 . 619 974 12 493 505 896La Kram 158 5 93 256 189 189 535Le Bardo 319 24 565 3 381 38 1800

Zaghioum - 1377 138 275 6 346 352 295Stierte 10 357 14 391 m 27 779 806 1659Nabut e 849 l 629 1478 140 1088 1228 2715

Baja 266 228 494 109 SS0 659 664Jendouba , 525 . 233 758 244 559 803 1163Le Ket 501 S 133 634 339 631 970 1131silana 339 123 462 237 445 682 694

sousee 26 490 13 467 996 156 643 799 1698Notwstir . 200 . 256 456 19 315 334 664N1oknlne . 205 . 148 353 56 171 227 800Nabdifa 379 . 122 501 162 490 652 849Koroua 435 1 242 678 205 810 101S 1261

Kauserine 305 . 139 444 254 515 769 729Sidi ouS id 464 . 149 613 4S7 479 936 904Gaefs . 413 180 593 129 909 1038 990Tozeur 104 . 170 274 35 375 410 35S

Sfax 43 1094 21 560 1718 604 1000 1604 4016GstAs - 451 216 667 314 666 980 979Kbitl . 143 , 102 245 52 325 377 860Zaruis . 684 196 880 236 774 1010 2495Tataoulne , 247 , 29 276 145 360 505 616

Total 256 10053 91 6551 16951 3941 14205 18146 30561

129 - AmJ 13Page 3 of 1S

tabte, A1.3: TECHNICAL DISTRIDUTION RATIOS

Data for 1968 Share of total CdReions Networks (km) No. of No. of Networks Substations Customers

NV LV STEC Custo NV BW NV BV STEC Custo _ LVmers mere

Tunis 1990 5004 1642 1742 2043 334980 11 17 16 26 30 28North 2386 4669 1353 1l1n 1240 169960 13 15 13 18 18 14Northwest 3114 3672 1631 717 651 121220 17 12 16 1l 9 10conter 3027 5272 1M 1249 1264 211020 17 17 17 19 18 18southwest 3153 2975 1286 638 582 101530 17 10 12 9 9 aSouth 86 8966 2662 1124 1098 261610 25 29 26 17 16 22

Totat 18146 30561 10309 6642 6878 1200313 100 100 100 100 100 100Tunisia

-- --- - -Ratio

No. of km of NV No. of km of LV No. of meters of No. of LV customersper substation per STEC LV per LV per STEI substation

(STEI + substation customer___ _ r customers) _ _

Tunis 0.589 3.045 15 204North 0.945 3.450 27 126Northwest 1.326 2.250 30 76Center 1.016 3.039 25 121Southwest 1.639 2.315 29 79South 1.607 3.368 34 98

Total Tunisia 1.070 2.965 25116

-130-Page 4 of 15

Power ionldD azm

6. The following table gives the 1989 regional breakdown of power supplied fordistribution and billed by this Directorate.

Tlbte A13.h: BREAKDOWN BY REGION

Regfon Enerry supplied X Energy billed X.____ CGWh) (GAh)

Tunis 1240.63 28.25 1125.40 28.22North 852.64 19.42 776.90 19.48Northwest 333.90 7.60 320.60 8.04Center 832.32 18.96 740.70 18.58South 730.03 16.63 635.40 15.94Southwest 401.24 9.14 388.40 9.74

Tota l 4390.76 100.00 3987.40 100.00

7. TIbs breakdown shows an area of high consumption comprising the neighboringregions of Tunis and the north, which account for 47.70% of total domestic consumption, and somecentes with an average level of consumption around Sousse and Gabbs. The city of Tunis and itssuburbs account for 28.22% of national power consumption.

l. eof PoW= o g distriution netorks

8. The pattern of developmen of the MV and LV networks is greatly influenced by theexpansion of rural electriflcation, which Is one of the key elements in the Distribution Directorate'smaser plan, the goal of which is to achieve a 75% electrification rate in 1991 (the rate for 1976 wa13%, and that for 1987 was 58%). The following table shows changes in the network from 1976 to1988.

Tabte A13A: DEVELOPMENT OF THE NETWORKS

_ _ _ 1961 j 1987 18 I

WV network (la) 660 11000 14872 16163 16955 17529 18146

LV network (km) 7700 15100 22234 25016 27118 29234 30561

No. NV/LY substationsPubtic 7354 8001 8500 9759 10309Private 4804 5477 5562 6229 6642

Total 3900 9030 12158 13478 14062 15988 16951

. - --- -- ............ _

- 131 -Page 5 of 1S

9. The breakdown of sales by sector shows the importance of the constructionIndustries (principally the cement works), which account for 19.30% of the energy billed; the cementworks alone accounted for 64.5% of the HV energy consumed.

Tabte A13.S: KV/IIW POE SALES BY SECTOR (1989)

AVerageDifference Turnover price

Consuvption beteen 198 (tD 000) per kWhSector OWN and 1989 (total)

(t) Totat Share (TO)

Extractive industries 209.0 3.1 8813 7.3 42.2Food and tobacco 195.8 2.0 9506 7.8 48.5Textiles amd clothing 172.7 10.5 8680 7.1 50.3Paper and pubtishing 77.3 -4.2 3251 20.7 42.0Chemical ad petroleum Industries 118.4 -4.2 6350 5.2 53.6Construction 769.6 8.4 30056 24.8 39.0Basic engineering 144.9 14.3 5810 4.8 40.1Niscellaneom 182.9 9.6 9632 7.9 53.7

Total 1 1870.6 6.3 82098 67.6 43.9

Purping: agricultural 154.5 0.0 6646 55.5 43.0Pusping: water supply and sanitation 166.8 10.5 7530 6.2 45.1Transportation and coimmuications 91.2 3.6 4715 3.9 51.7Tourism 157.2 9.7 8097 6.7 51.5Services 216.7 3.5 12294 10.1 56.7

Total 2 786.4 5.4 39282 32.4 49.9

GRAND TOTAL 2657.0 6.0 121380 100.0 45.7

Table A13.6: POWER SALES TO NV CUSTOMERS

Consmption (VAh) Turnover(TO 000) Average

AE Pcier priceCustomer Code (NW) Total Differ- Total Differ- per klh

ence o_ _ ence (TD)Nine de Cafsa 300 26 131.3 0.9 4801 16.6 36.6Collulose Kasserine 25 10 37.8 *15.0 1364 4.7 36.1El P. (act6rie) 220 9 76.3 4.7 2724 9.4 35.7El F. (fours a arc) 220 7 29.4 18.1 1057 3.6 35.9Cimenterie de Bizerte 211 10-16.5 70.4 8.3 2391 8.3 34.0Cimanterie de Gabls 211 15 89.2 16.7 3045 10.5 34.1Cienterie de Kef 211 19-21 114.4 13.5 4092 14.1 35.8Cimanterfe Soussm 211 22.5-23.5 116.3 6.5 4279 14.8 36.8Cimnterfe de Zaghouen 211 23-26 102.9 14.6 3745 12.9 36.4Nitro Idger Sousse 400 1.2 2.4 20.0 108 0.4 45.0Ciment Blanc K. 211 6.6 26.8 5.9 944 3.2 35.2SIAPE, Sfax 230 8 9.1 -9.0 429 1.5 47.1

169.8 806.3 7.3 28979 100.0 35.9

- 132 A na 13Page 6 of 1S

Tcnical AlgoM¢

Seefio2n of rernce netw,o

10. IThi study examines the various areas in which losses on the STEG distributionnetwork have been detected. The loss rate at each of these points is demhied by an "overallmethod, and short, medium or long-term recommendations will be made, matching the type ofproblesa Identified.

11. Given the extent and diversity of STEG distribution networks and the time available tothis mission, an exhaustive analysis of the networks was not possible. It was therefore decided toconcentrate on the networks in zones where consumption was homogeneous and representative of thedistribution system as a whole.

12. An initial analysis identified three major zones with a homogeneous pattern ofconsumption. As Table A13.17 indicates, the various regions of Tunisia can be divided into thefoUowing three categories:

- the first consists of regions characterized by a poor ratio of energy biled to energysupplied, and a ratio of about 0.5 between number of mMV and mber of mLV.This category consists of the North, Center and South;

the second is characterized by a high ratio of energy billed to energy supplied, despitea high ratio between number of mMV and number of mLV per consumer, the reasonbeing that the network is more recent and therefore certainy more efficient. Itconsists of the Northwest and Southwest; and

finally, Tunis is a special case, with a low ratio of energy billed to energy supplied,and also a low ratio between number of mMV and number of mLV per customer.Ibis in itself suggests that nontechnical losses in this zone will be high.

-133 -Page 7 of 15

Table A13.7: IDENTIFICATION OF ZONES

Zone Ratio A/ No. of mLV per LV No. of mlV ir LV Ratio.______________ ._________ customer and NV customner nWNMLV

Tunls 0.907 1S 6 0.40North 0.911 27 14 0.52Northwest 0.960 30 26 0.87Canter 0.890 25 14 0.56SCuth 0.870 34 17 0.10Southwest 0.970 29 31 1.07

Iv Ratio u Rnergy billed/Energy supplied.

13. One typical district was selected from each category: Nabeul, where agculture,tourim and industry are major activities; Sillana, a rural district, Is representative of the seond, adtwo districts (the city of Tuni, an urban district, and Bzzahr, a suburban district) were slected asrepreseative of the region of Tunis, which alone consumes over 28% of the energy supplied InTunisia.

14. In addition, these districts also meet the following criteria of representativity:

voltage levels: 10 kV and 30 kV;network structure: overhead and underground;distribution system: three-phase and single-phase;energy utilization: at medium and low voltage.

Tables A13.8 to A13.18 present the technical specifications for these districts.

-134- Ann1Page 8 of IS

Jn dent Criteri

15. A reprseave sample of the MV network In a given district is selected by meam ofthe following three Interdependent criteria:

Criterion 1 = rt Ppmax

Criterion 2 = EP (kVA/m)Outgoing feeder length

Criterion 3 = E P max (kVA/m)Outgoing feeder length

16. For each outgoing feeder in the zone, the value of each criterion is calculated,together with E P inst x outgoing feeder length, in order to identify those feeders assumed to have ahigh loss rate. Tbis provides the data for Tables A13.7 to A13.12 for the City of Tunis district andA13.13 through A13.15 for the district of Siliana. From these tables can be detemined thedistribution of feeders according to the value of each criterion. This provides the materi for TablesA13.16 to A13.18. This provides a "predominant interval* for each criterion; this is the intervaldefined by the lagest number of feeders. All feeders are then identified and the predominant intrvalfor the three criteria is also detrmined. This selection is weighted by taking one feeder in eachinterval adjacent to the predominant interval, up to a maximum of six additional feeders selected so asto provide feeders connected to most main substations.

-135- Annex13Page 9 of 1S

ii I B I NhI n H01~~~~ Cy l Sees

~~~~~~~~...... . _

§I . @0 Na oa- ,-X;

CyV..

Ii~~~~~~~~~~~~~~~~~~4

l}} R ,$g qsO ,a _ - 00. .0 0-_.0000**

-~~ ~ ~ ~ t -- ERnU-

~~~~~~~~~~~~~~~~~~~~~-

tlbte DA1X9. DISTItICt: CITY OF IUISMaIN UBSTATIr: TUNIS WIIU

Feeer .M.A. Lenth Winst p _ vim n8l mpIt*LeuthSLibstatoms (kC) CkA) (WA) P Lmmb Lle th (kVAI)

t. brine 1 0,S00 1T. Nwins 0 0.500 0Gare 1 9,48 7

antfleury 1 5,700 UITIK 0 0H. Cmlrees 1 2.300 1450 0.63 5R. Conrew$ 0 0T. Nerine 1S 5.960 4530 1957 334 1.10 O03 38919Soreti6 ? 5,640 751S 3585 2no 1.33 0.6 42385 aBiat 16 5,S27 6SS 3723 173 1.17 0.67 3M677TurquSe 11 3.42S 3370 1818 185 0.98 0.53 1S142ojeaui 10 3,227 3761 1818 207 1.17 0.56 1213Aorfcultor 11 3.460 5200 1784 291 1.50 0.52 17992BCT 16 5,57 10905 3256 335 1.96 0.58 60795Ctaridge 16 S,640 9910 4676 212 1.76 0.83 SS892Africa 9 2,615 5393 2234 241 2.06 0.8S 14103ICrfe 27 7,500 10525 4676 225 1.40 0.62 8

Total 152 67.049 7114

01I IL

Ibt& A1LI9: DISOtICT* CITV OF 1?USPlAIN SUBSTATIU: TUNIS WEST I

Feeder NV(LV Length Winat P mx metiN Smt LU P f,nstLertihSuhstaet o C (kYw) CkVA) P mx Length Lngth (kVAflt)(ItVA/ft- CIMAm)

Karoun 19 5,060 5313 1.05 26886UTTI 1 1,650 3400 2.06 5610schtel 2 1,430 3630 2.54 5191BSwricho 37 9,145 10065 4728 2.13 1.10 0.52 92044Dasuat 30 11.915 100l9 3585 2.81 0.85 0.30 120091Francevilte 26 12,335 7315 4469 1.6 0.59 0.36 90231Kitatn 17 6,755 7245 4468 1.62 1.07 0.66 48940Ben MarfI 29 12,010 10800 2511 4.30 0.90 0.21 129708Plantation 19 5,740 7993 3793 2.11 1.39 0.66 4S880El Nef ir 17 7,175 6755 3308 2.04 0.94 0.46 48467SSSUT 3 6,170 8178 2909 2.81 1.33 0.47 50458STIT 26 7,350 12685 3983 3.18 1.73 0.54 93235Uettoiemnt 14 5.150 721S 3983 1.81 1.40 0.77 37157Berthelot 10 3,590 4565 1766 2.58 1.27 0.49 16388Riot 11 3,395 4360 3256 1.34 1.28 0.96 14802

Total 261 98,870 109598

'III

tae A1jS1: DISTRICT: CIT OF TUNIS_AIN SUBSTATIO I: Tt131 WEST 2 _ _

Feeder NY/LV Length Vfinst P Max sPinmt fPwM P & Pinstftwigthsubsetation Cb) (WA) (OA) P mx Length LenIthMkV (kVA*im)

MA/mJ AJm

RTT 0 1.550 0 0.00 0Kartoum 2 1,380 1260 0.91 1739CEN I 0,085 1000 11.76 85Fi let 19 7,905 10945 1.38 86520SiT 18 7,035 4420 0.63 31095Carrwud 22 12,790 13880 1.09 17752SB. Seed 25 18,485 8395 0.45 155182Banana 35 18,446 11850 0.64 218585Frigori f fque 22 9,895 6630 0.67 656C4Sidi Assfca 14 8,665 Au90 0.56 42372Beaux Arts 5 3,430 2655 0.77 91o7Vetwart 25 13,275 7610 0.57 101023Nutrition 16 10.495 4180 0.40 43869

Total 204 113,436 60090

Tabte A13.12: DISTRICT: CITY OF TUNISPAIW SUBSTATION: TNItS NORTH

Feeder WVfLV Lenoth )Pinst P max _SP Pnnst*LengthSubstations (km) (MA) CkVA) P mx Length Lenth CkVAtkm)

Palestfne 27 8,990 8600 1957 4.39 0.96 0.22 77314Chebbf 15 4,385 6310 1212 5.21 1."4 0.28 27669Syrie 7 0,520 2060 207 9.95 3.96 0.40 1071Avnf r 11 19 7,620 6340 2523 2.51 0.83 0.33 48311Avenir 12 21 10,810 9090 3377 2.69 0.84 0.31 98263Avenir 16 8 5,390 3255 2840 1.15 0.60 0.53 17544Ibn Roch 12 3,958 3695 1090 3.39 0.93 0.28 14625Pexfque 44 22,060 15278 4607 3.32 0.69 0.21 337033Chargufa 41 14,650 10938 4797 2.28 0.75 0.33 160242TuLipes 14 6.660 4505 3256 1.38 0.68 0.49 30003

Total 208 85,043 70071 ELR

TableA131: DISTRICT: CITY OF lIIISMAIN SLSTATTION: ZANIRUN

Feeel e r uP Length imnst P mx 3 t Zimnst Lt Pinst*LaengthSustattemn Cb) (WVA) CkVA) P max Legh- Length CWAMM)

__ ___- c )Raf 28 14,919 10645 2979 3.57 0.71 0.20 158813Noubltfe 19 13,770 7385 2z02 2.73 0.54 0.20 101691Msrabou 21 13,080 6685 4538 1.47 0.51 0.35 87440

Total 68 41,769 2471S

TsbtlAI3.14: DISTRICT: MADItLNAIN SUBSTATION: WHAMET

Fewer NVLV Length DInst P am >"t Pinst*LengthSubstatiom (ktm) (kVA) CkVA) P max Length Length (VA*km)

(kYA/m) (kVAIM)

S. Argoub (1201) 120 88,384 18002 13302 1.35 0.20 0.1S 1591Enf dia (1202) 90 S1,890 1973 7205 2.74 0.38 0.14 1026Nabeul (1203) 156 72,425 50240 - 0.69 - 3639Elkoutn (1204) 19 _ 8213 3948 2.08Sultan (1205) 20 10,398 8313 3525 2.3S 0.80 0.34 86R. Jannet (1206) 19 10,469 9375 2950 3.17 0.89 0.28 98

Total 424 233,566 113916

Teble A13.15s: DISTRICT: MASLFAIN SUSSTATION: GR0NLIA

Feder NVtV Length Winst P max Wjns winst LMX Pflst*LengthSubstatians Cki) CkVA) (WA) P m Length Length CkVA'kr)

Ck_AWM (kWA/r)

1e.l1 (5001) 87 70,954 19464 9222 2.11 0.27 0.13 1381E. Nord (5002) 58 43,266 16420 9260 1.77 0.38 0.21 710Solinan (5003) 136 112,085 23419 12153 1.92 0.21 0.11 2625Z1 Grme (5004) 66 34,211 19710 392 2.35 0.58 0.25 674N. SoueL. (5005) 138 88,384 22765 8504 1.77 0.26 0.10 2012

Total 485 388,900 101778

Table A13.16: DISTRICT: NASEULLMAIN SUBATIOU: * KOM

Feeder NV/LV Length ZPinst P max xpirt ZPinst P x Ptnst*LengthSubstatiom (kn) (kVA) (kVA) P mx Length Length (kVAnm)

_______________ ________ ____ _________ (VA/rA ) (W AM)

Dressen (1301) 70 79,834 953 2161 4.41 0.12 0.03 761nIzraa (1302) 90 62,465 14697 10195 1.4 0.23 0.16 918Korba (1303) 25 11,510 6275 2838 2.21 0.54 0.25 72Kelibia (1304) 229 227,157 22265 7074 3.14 0.09 0.03 5058llauaria C1305) 190 246,518 20944 6625 3.16 0.08 0.03 5163

Total 604 388,900 101778

aILt;

- 141 - A 1Page iS of iS

Tsble AILjZI INTERDEPENDENT CRITERIADISTRICT: CITY OF TUNIS

Criterion I (0.11 (1.22 t2.31 t3.41 £4.51 15.3£

Numer of feeders 0 10 20 7 3 3

Criterion 2 [O;0.51 [O.5;11 t1;1.53 t1.5:2J 121t

Number of feeders 0 22 1S 4 2

Criterion 3 CO;0.251 tO.25;0.5l IM.5A0.M5 1O.75;[ .

Number of feeders 9 18 12 4

Table A13.18: INTERDEPENDENT CRITERIADISTRICT: NASEUL

CrIterion 1 [0.11 [1.21 £2.31 C3.41 14."t

Number of feeders 0 4 I 3 2

Criterion 2 CO;0.251 [O.25;0.51 10.5;0.751 [O.75;11

Murber of feeders 6 4 3 2

Criterion 3 t00.1251 EO.12;0.251 CO.25;0.371

Number of feeders 6 7 2

17. This gives the following feeders for the diricts In question:

Ditrict: City of Tunis: Tanit - Imer - B.Miled - BCT - Agricultor - Turquie - El hafir -Daudet - Avenir 1 - Avenir 12 - Charguia.

D41ria: Nabeu: : B.Argoub - Mazzraa - Kelibia - Haouaria - Belli.

18. It should be noted that in the cas of the District of Nabeul the intersection of thethee criteria produces an empty set. Consequently priority has been given to those feeders assumedto have a high loss rate.

-142- 1Page 1 of 12

CROSS-SECTION CHANGE

1. Installing a cable with a larger cross section, and thus lower resistance per unit length,reduces losses per unit of power transmitted.

The loss reduction, in kW, is given by the following formula:

gain = 1000 x L x (rl - r2) S2/V2

where:

ri = resistance per unit length of conductor i, in 0/kmS apparent power in kVAU = inteIphase voltage, in kV

A section should be upgraded when the following is true:

Annual capital investment cost_________________< Annual cost of one kW loss

Reduction of Losses [kWV

This ratio can be used to establish a threshold output S, beyond which investment is profitable.

NO: since the eimated discount rate is 10%, the annual cost of the works is 10% of the totalinvestment cost.

2. For the overhead network, the total investment cost is the sum of the following costs:

installation of cable with cross section S2+ removal of cable with cross section SI+ insalling new poles W/

WU/ On awrag, own doirf &# eing poks wuW be replacea

- 143 - A= 14Page 2 of 12

3. for the underground network, the total investment cost is broken down as follows:

laying of cable with cross section S2+ accessories junctions and ends)+ repairs+ cable trenches

4. In the underground networks, removal of the original cable with cross section SI is notfinancially worthwhile, even taking into consideration the possible recovery of copper from theconductors.

5. The following table shows the total investment cost for the various types of network andconductors:

tabte A14.1: INVESTENT COSTS FOR THE VARICUS CONDUCTOR TPES

New cable Inestment Lost

Low voltage rntwork3i5' Au 7.12 TD/i70' Alu 8.67 TDIm

Wedium voltage network

Overhead tines 54.6 Alm 5805 TO/km148.1 Atm 9670 TO/km

Underground cables 240' Alu 64592 To/km

6. When the diameter of the cable Is doubled, the strength of the current in any given sectionis halved, the losses for each line are divided by four, and total losses are therefore divided by two. lhewcrren strength corresponding to the economic break-even point for thbis operation is determined by thefollowing formula:

Loss reduction > annual investment/annual cost of one kW of losses, from which weobtain:

12 > (AnnUal InveStmenta cost of one kW of loss) * 23000 r

r = linear resistance of the cable, in 0/km

7. From the total number of feeders studied, we select those segments which convey currentat a level of intensity greater han, or equal to, the threshold level for reconductoring the secdon. In eachcase, the total savings in Tunisian Dinars (ID) can be calculated, since a loss reduction of 1 kW producean annual saving of TD 360.5 for the medium voltage network (see Annex 2, 'Calculation of Loes).

- 144- MM 14Page 3 of 12

I'us, for eah segment, and then for each outgoing feeder, the immediate rate of return RR) can becalculated. It Is defined as foliows:

Discouned annual savings in TDTRI =

Total investment cost in TD

For each outgoing feeder, the results are as follows:

Jghle AUJ: RECONIOCT0RING OF THE HACURIA OUTGOING N FEEDER(DISTRICT OF NASEUL)

P (IdE) Length Loss Total cost(m) sect I Sect 2 reduction (TO) in

2596 80 22 Cu 148.1 Atm 386 774 182557 80 22 Cu 148.1 Atm 376 M74 1lx2557 520 22 Cu 148.1 Alm 245 5028 18o2492 810 22 Cu 148.1 Alm 3617 7833 17g2285 1540 22 Cu 148.1 Atm 5782 14892 14X2235 900 22 Cu 148.1 Atm 3233 8703 1322026 430 22 Cu 148.1 Atm 1269 4158 11X

4360 17111 42161 15X

- 145 - AnuIPago 4 of 12

table A4t3: RECOUCTORING OF THE RELLI OUTGOING NV FEEDER(DISTRICT Of NASIUL)

P &Id) Length Loss totol cost(m) sect 1 sect 2 re uctton (TD) IRR

- (") . . .. .~~~~~~-(W

4573 80 1 Cu 148.1 At 1607 774 75X450? 130 17 Cu 148.1 Al 2536 125? 73n4446 140 17 Cu 148.1 At 265 1354 n446 670 17 Cu 148.1 Al 1270 6479 7T124427 280 17Cu 148.1 Al 5270 2708 7024349 260 17 Cu 148.1 Al 4723 2514 6824310 610 I7 Cu 148.1 Al 10883 S"9 67X4271 310 1? Cu 148.1 Al 5431 2998 6524232 230 17 Cu 148. Al 3956 2224 6423533 80 7 Cu 148.1 Al 959 74 45X353 370 17 Cu 148.1 Al 4436 3578 4523494 670 7 Cu 148.1 Al 7856 6479 43302 270 17 Cu 148.1 At 2827 2611 33263 310 l7 Cu 148.1 Al 3170 2998 3823244 220 I? Cu 148.1 At 2224 2127 3823205 410 l7 Cu 148.i Al 4045 3965 3723205 200 17 Cu 148. Al 1973 1934 3723168 7o 17 Cu 148.1 Al 6940 6942 363149 400 l7 Cu 148. Al 3810 386 3622843 550 29 Cu 148.1 Al 2136 59 1422715 840 29 Cu 148.1 Al 2975 8123 14225S9 810 lT Cu 148.1 At 5094 7833 2322438 140 29 Cu 148.1 Al 400 1354 11X2316 280 29 Cu 148.1 Al 2708 102

8980 99351 86837 412

- 146- &= 14Page 5 of 12

Jlbtg A14.4: RECONODUCTORING OF THE LAKCES OUTGOING NV FEEDER(DISTRICT OF SILIANA)

r (d) Lenth Loss Total cost(M) Sect I Sect 2 reduction (TO) IRN

6168 2430 54 Atm 148.1 ALm 42855 23498 66X6045 450 54 Alm 148.1 Al. 7623 4352 63X5807 860 7S Alm 148.1 Alm 7588 8316 33X485S 280 75 Alm 148.1 Alm 1734 208 23X4855 1000 75 Alm 148.1 Alm 6168 9670 23X4836 750 75 Alm 148.1 Alm 4590 7253 23X4797 540 75 Alm 148.1 ALm 3251 5222 22X4782 860 75 Alm 148.1 Alm 5146 8316 22X4M 1390 75 Atm 148.1 Alm 8283 13441 2,34741 80 75 Atm 148.1 Al. 471 774 22'34739 1790 75 Atm 148.1 Alm 10519 17309 2234711 80 75 Alm 148.1 Alm 46S 774 22X4708 660 75 Atm 148.1 Alm 3828 6882 22X4708 140 75 Alm 148.1 Alm 812 1354 22X4708 90 75 Atm 148.1 Alm 522 870 22X4439 1150 75 Alm 148.1 Alm 5929 11121 19X4210 S00 75 Alm 148.1 Alm 2319 4835 17X4190 650 75 ALm 148.1 ALm 2986 6266 17X4115 150 75 Alm 148.1 Alt 665 1451 17X4112 440 75 Alm 148.1 Alm 1770 3868 16X2775 130 22 Cu 148.1 Alm 720 1257 2132760 390 22 Cu 148.1 Alm 2136 3771 2032663 160 22 Cu 148.1 Alm 816 1547 19X2563 80 22 Cu 148.1 AL 378 774 18X254 300 22 Cu 148.1 ALM 1396 2901 1732544 600 22 Cu 148.1 Alm 2792 5802 17X2396 S580 22 Cu 148.1 Alm 23036 539S9 1532296 7800 22 Cu 148.1 Alm 2569 75426 1432296 200 22 Cu 148.1 Alm 758 1934 14X

29490 121572 145147 303

-147 - Anna 14Page 6 of 12

8. In order to evaluate the rate of technical losses on STEG's low voltage disibutionnetwork, losses were calculated for a number of low voltage outgoing feeders that were representativeof the networks in each district selected for the study. As these districts themselves were charcteicand represenative of Tunisian distribution networks, one can then determine the overall loss rate on thelow voltage network.

Calculation of Losses on an Outgoing LV Feeder:

9. For these calculations, the following assumptions were made:

the load is evenly distributed over the length of the outgoing feeder;

losses in consumer connections were not taken into account.

10. If we know the power demand in the outgoing feeder and the distribution mode (threephase or single-phase, LI or L2, i.e, 380 V or 220 V), the following values can be detenninedsuccessively:

peak load percentage (i,,);

intenity of current transmitted (LW);

- losses (Loss.) for each segment; then

loss rate for the outgoing feeder (% Loss)

by means of the following equations:

i,, = (I/L) x '"S

Loss.,. = r,^ I,,, vL,

% Loss= 5 Loss.,/P.

in which:

I current intensity in the outgoing feeder, recorded at the MVALV substation (A)

- 148 - ADDM.14Page 7 of 12

L = total length of outgoing feeder (km)

L." = length of segment (km)

r,, = resistance per unit length of the segment (0/km)

P,,Sx, = power demand recorded at the outgoing feeder bay (kW).

X = Cost of network losses in TD/kW

Y = Annual investment cost in TD/km

And thus:

yS 2 UVj

X 1000(rl-r2)

11. This value is called the "threshold power," since it marks the break-even point fork<vestmnt.

12. It should be noted that, since the estimated discount rate is 10%, the annual cost of theworks is 10% of the total investment cost.

13. The following tables can be constructed:

Table A14.5: RECONDUCTORING INTO 35' ALU - THREE-PHASE NETWORK (52)

Threshold power Threshold currentOrtplnal cress-section (kVA) strength (A)

29' Alu 33.29 50.5816' Alu 13.78 20.9340/10 Cu 19 13 29.0730/10 Cu 11.00 16.7217.8' Cu 37.18 56.4810' Cu 14.81 22.506' Cu 9.76 14.82

- 149 - An=Page 8 of 12

Iab.ae A14fis RECONOUCTORING INTO 70' ALU THREE-PHASE NETWORK t2)

Threshold poor THreshold currentOrtignal cross-section (kVA) strength (A)

50 Atu 37.34 56.7340r Atu 27.26 41.4238' Atu 25.73 39.093S' Atu 23.61 35.8t29' AMu 19.86 30.1716' Atu 12.78 19.4240110 Cu 15.74 23.9130/10 Cu 10.80 16.4017.5' Cu Z0.46 31.0910' Cu 13.44 20.426' Cu 9.79 14.88

14. In cetai cases, it is planned to double the diameter of the cable (first section to 702):

Conversion to 702 -> 2 x 702: I threshold = 41.41 A

15. Ihe mission observed that in rural areas like Siliana the monophase network is geneallycorrectly structured and has a low loss rate. Consequently, no reinforcement Is planned for the single-phase work in this area

16. From the sample of feeders studied, those segments of outgoing feeders transmittingpower equal to or greater than the most cost-effective threshold level for reinforcement are selected.Likewise, in each case, the savings in TD to be derived from this reinforcement are calculated, on theassumption that a 1 kW reduction in losses corresponds to a saving of TD 471.4 (see "Calculation ofLosses"). The immediate rate of return (IRR) is then calculated for each section and feeder, inaccordance with the following:

Projected savings in TDIRR = _ _ _ _ _ _ _ _ _ _-

Total inlvestment cost in TD

-150 - Am14Page 9 of 12

Thus, once the break-even point has been reached for the two cross sections (352 al and702 al), the option providing the higher IRR for the section is selected. Moreover, by classifying theoutgoing fiedes in descending order of IRR, a schedule of work can be prepared that spaces the workto bedoneovertime. In effect, prioritywillbegivento the feeders with thehighestlRls. Thismediodof calculation also enables the loss re subsequent to reinforcement to be determined for each outgoingfeeder,, together with the new loss rate for the district as a whole.

17. The results per outgoing feeder for the low voltage network are as follows, when weapply the method and calculations defined in Annex 3:

Tabte AWf RECONDUCTORING OF THE EL DJAZIRA OUTGOING LV FEEDER(TUNIS CITY DISTRICT)

Length Loss Total costI (A) (a) sect 1 Sect 2 reduction (TO) hR

63.00 90 710' ALu 2'0* Atu 287 780 17%27.9f 10 6V Atu 35' Atu 54 71 36%

100 1 851 19%

Tkbl A14.i8: RECOIiDXCYORING Of THE EZZITOUJA OLTCOING LV FEEDER(TUNIS CITY DISTRICT)

Lenoth Loss Total costI (A) tm) Sect I sect 2 reduction (TO) IRS

235.00 10 70' 2*700 497 87 27ox47.50 50 70' 2*70' 80 434 12%

60 577 521 52X

- 151 - Am 14Page 10 of 12

tableiauAIL.% RECONDUCTORING OF THE ONAS OUTGOING LV FEEDER(DISTRICT OF E22AHRA)

Length Loss Total costI (A) (i) Sect I Sect 2 reductfon (TO) IRR_ _ _ _ _ _ _ _.. _ _ _ _ _ _ _ . _ _ _ _ _ _ ( U _ _ _ _ _ _- _ _, _- _ _ _ _ _ . _ _

76.00' 60 70 Alu 2*70# Atu 279 520 25%68.92 45 70' Atu 708 ALu 230 390 28%17.47 20 30/10 Cu 352 AMu 33 142 11%

125 542 1052 24S

Lblj Ali4 l: RECONDUCTORING OF THE INDEPENDANCE OUTGOING LV FEEDER(DISTRICT OF EZZAHRA)

Le.gth Loss Total costI (A) Cm) Sect I Sect 2 reduction (TO) IRR

116.00 75 70 Atu 2*701 AMu 812 650 59%59.07 25 16' Alu 70' Atu 425 217 93%51.86 30 16' ALu 70' AMu 394 260 71%43.22 35 16' Alu 70' Alu 319 303 5OX33.14 45 16' AMu 70' AMu 241 390 29%20.07 30 16# Alu 70' AlU 59 260 11%

240 2250 2080 51%

Euahre DOstriet, Ghandf outgoing feeder: no reconductorlng.

lTae A14,11: RECONDtWCTORING OF THE KAHENA OUTGOING FEEDER(DISTRICT OF EZZANRA)

Length Loss Total costI (A) (__ ) Sect I Sect 2 reduction (TO) tRR

38.48 20 3S5 AMu 70' Atu 42 173 12%59.00 20 70' Alu 2*70' Alu 56 173 15%

40 98 346 13%

-152- AfhPage 11 of 12

Tabt A14l12: RECONDUCTORING OF THE ECART NMRD Al OUTGOING LV FEEDER(DISTRICT OF NABEUL)

Length Loss Total costI (A) (i) sect I sect 2 reductIon (TO) IRn

80.48 125 386 AMu 70 Atu 975 1084 42165.8B 110 38' Atu 701 AMu 575 954 28147.85 270 38' AMu 70' Alu 744 2341 15X31.07 1SO 17.8' AMu 708 Alu 276 1301 101

655 2570 5680 21X

TXbt A14.13s: RECONDUCTORING OF THE ECART NORD A2 OUTGOING LV FEEDER(DISTRICT OF NABEUL)

Lenoth Loss Total costI (A) cm) Sect I Sect 2 reduction (TO) IRR

84.52 90 50' Alu 70' Atu 367 780 22X72.09 220 50' AMu 708 AMu 653 1907 1637.29 50 40/10 Cu 70' Alu 224 43 24

360 1244 3121 19X

Tabte A14.14: RECONDUCTORING OF THE ECART NORD A3 OUTGOING LV FEEDER(DISTRICT OF NABEUL)

Length Loss Total costI (A) Cm) Sect I sect 2 reductfon (TO) IRR

53.12 370 29' Alu 70' Alu 2109 3208 31X31.52 160 298 Alu 70' Alu 361 1561 11M

550 2470 4769 24X

*153 -Page 12 of 12

taettM AHs.15s RECONDUCMING OF TNE ECART NORD A4 OUTGOING FlEDE0(DISTRICT OF AEUL)

Lnogth Loss Totat costI CA) (m) Sect 1 Sect 2 rodtwtlon (TO) 1R3

_________tO _ _ _ _ _ _ _ _ _ _ _ _ _C )_ _ _ _ __ ___ _ _ _ _

96.88 120 70' Alu 2*70' Atu 906 1040 41%82.8 160 70' Alu 2*70' Atu 884 1387 30%26.02 480 40/10 Cu 70' Alu d212 4162 14%

760 3002 658 212

Ilhtg A14h6A: RECONDUCTORING OF THE KAWNIA LV OUTGOING FEEDER(DISTRICT OF NAUUL)

Length Loss Total costI CA) tm) sect I Sect 2 rduction (TO) IRR

122.00 35 70' AMu 2*70' AMu 419 303 65X106.60 50 35' Atu 70' Alu 812 434 88X101.38 90 29' Atu 70' AMu 1869 780 113244.45 60 29' Atu 70' Alu 239 520 22X51.70 40 40/10 Cu 70' AMu 344 347 4?743.57 40 40/10 Cu 70' Alu 244 347 33m29.05 110 40/10 Cu 70' AMu 2S} 954 15S

425 4226 3685 542

TWO( A14.17s RECONDUCTORING OF THE ARSOLINE OUTGOING SINGLE-PHASE LV FEEDER(DISTRICT OF NABEUL)

Lenth Loss Total costI (A) Cm) sect I Sect 2 reduction (TO) 133

95.00 100 351 70' 430 867 23X73.88 120 35' 70' 312 1040 13X34.01 70 6' 35' 186 496 18n

290 928 2405 182

- 154 - Annexi1Page 1 of 1

TllANSFORMOR OPRATION IN TIHE IV/MV SBTATIONS

±bA 15.1t LIST OF SUISTATIONS FOR WHICH IT IS NORE ECONMI4CALTO PUT ONLY ONE NV/NV TRANSFORMER INTO SERVICE,

SWITCHING OFF THE SECOND TRANSFORER(1989 DATA)

Annual AnnaNVA NW NVA Pcore PJoute Saving Gain_ vlalegmnt peal -pPk kV kV To INh

0Nralte 2°40 16.0 My.7 25.3 195 4670 140N. jaml 240 19.S 21.6 25.3 195 2460 1000. zerm 2*40 16.0 1T.? 25.3 195 4670 140Jaidoub 2*40 17.0 18.8 25.3 195 4080 130Oeseletfi 230 15.0 16.6 25.0 160 3280 113Zahroui 2*30 13.5 15.0 21.0 160 2890 9890/O kV

Sfdf Nwrour 2*40 16.0 17.7 26.6 195 5130 151Zarafa 240 13.0 14.4 34.0 195 9350 243Zbrouni 2*40 19.5 21.6 26.0 195 2700 1289030 kV

Karomua 2*40 11.0 12.2 25.3 195 7030 182Tunis Center 2*40 21.0 23.3 25.3 195 1340 80sono kV

Tunis Nord 2*30 19.5 21.6 29.0 160 720 7690/10 kV

NdRutt 2*40 16.0 17.7 34.0 195 7820 215

Totat 56140 1796

- 155 -16

Page 1 of 7

GUIDEf FOR PREPARiNG MAINTEIANCE PROCEDURES

gneal: usfation for maintenance ogerations in an electricit system

1. The purpose of maintenance operations is to maintain the power system in goodcondition so as to guarantee:

the safety of personnel;

proper operation of the equipment.

2. The aim here Is to reduce the possibility of exposing the public and the operatingpesonnel to electrical risks. Electrical equipment is initially designed to confonm to safetyregations; it is up to the distributor to ensure that it continues to do so throughout its usefid life.

3. TIbs consists of reducing the risks of equipment breakdowns that could lead tofteuptions In supply. These failures could be the result of:

equipment working improperly as a result of age, wear, etc.;

specific environmental conditions: pollution, corrosion, animals;

- exceptional circumstances (atmospheric conditions, damage caused by third parties,vandalism).

4. These objectives can be achieved through activities ranging from monitoring theequipment to replacing it, and encompasses all stages of mainece.

S. It is not easy to define a mai ce policy since it basically involves selectig aseries of measures in a context of multiple contradictory constraints.

6. It is obvious, for example, that a maintenance policy that guaranteed total service reliability byiminang all network ptoblems would be economically harmful, as would a very limited and tmid

policy, due to its effects on service continuity. A maintenance policy is therefore a

-156-Page 2 of 7

reasonable compromise between doing everythinga and "intervening only where and when necessay,just before the Incident." lTis compromise consists In finding a balance between the economic costof the meaures taken and the cost for all equipment breakdowns.

Bases of a maintenance poic

7. The establishment of an appropriate maintenance policy should follow the followingtheoretical diagram:

Information -> choice of actions-> actions-> validation.

B. An initial diagnostic analysis of the equipment should be made, to evaluate a priorithe effectiveness of the policies selected, followed by an a posteriori validation of the actions thathave been taken. However, this theoretical approach must be tempered by pragatism In light of theoperators' experience, since very often it is hard to determine the qualitative improvement toequipment and It can take several years to evaluate a maintenance policy.

9. The prerequisite for all maintenance operations is the gathering of relevamt data. As afirst step this requires a diagnostic analysis of the equipment to provide data on the physicalcharacteistics of system components, their location and age, and the sequence of events that mayhave affected their operaton. It also involves preparing cartographic surveys of all or part of theelectric pawer system, with permanent flagging of defects and incidents.

10. This information system must also make special provision for the upward flow of datafrom the operators: deficiencies detected during normal operations, searches for defects, emergencyrepairs, and maintenance work. In recording this information, duplication should be avoided; theremust be one file, and only one, for each category of equipment - for example, one file for each MVfeeder, and so on.

11. Another very importan source of data is comprehensive analysis of all incidents anddefects that affect the components of the electric system, In order to understand their caus and, ifpossible, draw lessons for the future, especiaWly in regard to decisions to be taken in similarconditions or relating to identical components.

- 157 APage 3 of 7

12. A mntenance policy is based on observing a number of requirements.

(a) R lg e. These generally involve observing safety regulations, forexample, minimum distances to maittain between conductors and the ground, betweenconductors and buildings, and maximum grounding resistances.

Verifying that equipment conforms to these safety regulations is an important part ofmaintenance acdvities. Ibis verification will be performed on a case-by-case basis asmaintenance work is done.

(b) Ser-vce continuit imperaie. These are expressed in the form of various indicators,such as the number of MV feeders, the number of permanent defects per 100 kin,amount of energy unsupplied s the result of a breakdown, etc.

If the values of these indicators exceed predetermined thresholds, maintenanceoperations can be planned at the time the problems occur.

(*c) Prweveive maintenance This is generally based on maintenance schedulesrecommended by equipment manufacturers, but also, and particularly, on theexperience the operators acquire by opemting and mantining the equipment.

(d) Ec L ens. Defining a maintenance policy, as already noted, is acompromise between "doing everything" and very selective intervention just beforethe failure or breakdown. This compromise reflects a priority ranking of the variousactions (which the data colleted will suggest) using a cost/benefit method, in light ofthe savings to be expected from improvements in the continuity of supply and inproductivity following a reduction in the number of failures and, hence, in the nmberof emergency repairs.

- 158 -Page 4 of 7

Mantenance prgrm

13. A multiannual mainteance program, including actions by category, should beprepared in light of the preceding considerations and the resources available.

14. This program must also be consistent with investment programs that cover equipmentrehabilitation and reinforcement, to avoid redundancy in maintenance actions or in the use ofresources.

1S. The program will be established according to equipment type, since it is impossible toestablish mantenance rules valid for all the components of an electricity system. In practice thefrequency of incidents varies from one piece of equipment to another in light of:

(a) the initial uneven quality of the equipment;

(b) the variety of external constraints;

(c) the uneven quality of previous maintenance work on the equipment.

6. The scope of the work to be planned will vary in light of the information availableand the kind of equipment involved, ranging from occasional visits to routine maintenance, andincluding regular visits and light mainteance as and when necessary.

MV!gxvbead netwQrJe

t?. Maintenane opemrions on this category of structures should not be routine. Theywill be undertaken on the basis of the following information:

(a) information supplied by oprators. These are the specific problems detected byoperating personnel. These deficiencies should be located on a map and attended tovery rapidly. When problems the operators have identified are attended to prompdy,the operators are encouraged to continue reporting problems and the informatonimproves, both in quality and in quanity;

(b) oeall analis of incident, which enables the detection of weak points to bemonitored and, thus, helps detmine general maintenance guidelines for esh type ofequipment;

- 9 16

(c) routine Iiine inspec, as far as possible by helicopter at intvals of four yeas.The frequency of inspections could be adjusted in light of the number of failur perMV feeder. The inspections will serve to identify iregularities, locatiors wherepruning is needed, and other weak spots so that the amount of work ned ca bequantified. Repairs should be begun immediately fllowing the npectIons, a shouldpruning;

(d) casioal vi, at the request of the operators to confirm or deny ft e o ofless obvious problems on the network.

18. Overbed brk sWitC: maintenance will be perfrmed followinS line Inspecios.Tbis should as far as possible be hot-line maintenmce.

LY overbead netorSc

19. No routine equipment inspection. Occasional inspections will be scheduled tovulnerable parts of the network known to the operators or identified by the statstical record onincidents. The resulting maintenance operations will be economically justified and assied a priorranking according to the savings expected.

IAdrgmY nd V/VI Lq=rk

20. No preventive maintenance is recommended.

Me;emmCLof eartbing quality

21. The frequency of measurements will vary according to the zone and equipmen Thefollowing intervals could be envisaged:

(a) HV/MV substations: annually

(b) overhead MV network:

. break switches: every 5 years

* poles: every 10 years

* surge arresters: every 10 years

-160-Page 6 of 7

(c) MVILV substations:

. grounding connections: every 5 years

w neutral wire grounding: every 10 years.

22. The mission recommends:

(a) a routine inspection every five years to take measurements of earthing quality.However, the inspection schedule should be adjusted to the schedule of other actionsin the substations, such as redistribution of the transformers, replacement ofequipment, and operating maneuvers;

(b) occasional Inspections:

-when problems occur;

in specific cases known to the operators (substations along the coast,pollution, humidity).

These visits will lead to two kinds of maintenance:

light maintenance performed at the time of, or right after, the visit;

pianned maintenmce following technical and economic justification.

23. Routine maintenance will be performed on these, firstly because of their sensidvityand the difficulty of calculating the probability of breakdowns, and secondly because of thedisproportionate economic consequences of incidents that may affect them, when compared to the costof mantning them. However, the mantace Intervals should change in light of equipmentImprovements and operator eperience. One can expect:

(a) a monthly Inspection to verify:

the overall good condition of the equipment: HVIMV transformer, remotecontrol equipment, capacitors, MV breakers;

the overall good condition of the automatic devices;

- 161 - An 16iPage 7 of 7

the operating records of the breakers and recloses;

the indicator reading;

lighting, heatig and air conditioning;

the condition of the premises.

(b) routne mainenan:

breakers and fteir associated equipment, every 18 months for equipment atis insulated in oil;

operation of capacitor banks, every 18 months:

capacitors

capacitor batteries, annually;

c capacitor bank break switches, at the same time as the capactor breake,tin other words, every 18 months for equipment that is ilated In oil.

- 162 -

ENERGY SECTOR MANAGEMENT ASSANCE PROGRAMME

COMPTED ACTIVITIES

CounSq ActvIy Dae Number

SUP-SAHARAN ARCA (APR)

Africa Regional Anglophone Africa Household Energy Workhop 07/88 085/88Regional Power Seminar an Reducing Electric Power Sytem

Lose in Africa 08/88 087/88Insitional Evaluation of EGL 02/89 098/89Bioma Mapping Regional Workshops 05/89 -Francophone Household Es'ergy Wodshop 08/89 103/89Interafrican Electrical Engiueering College: Proposals for Short-

and Long-Term Developmnt 03/90 112/90Biom As ssmet and Mapping 03190 -

Angola Eme Asent 05/89 4708-ANGPower Rehabilitation and Technical Assistance 10/91 142/91

Benin EnergyAssent 06/85 5222-BENBotswana Energy Asssment 09/84 4998-BT

Pump Electrification Prefessibility Study 01/86 047/86Review of Electricity Service Connection Policy 07/87 071'87Tui Block Farms Electnfication Study 07/87 072/87Household Energ Issues Study 02/88 -

Urban Household Energy Strategy Study 05/91 132/91Buwkia Faso Energy Asm mt 01/86 5730-BUR

Technial Assistance Progm 03/86 052/86Urban Household Energy Strategy Study 06/91 134/91

Burundi Energy 06/82 3778-BUPetroleum Supply Management 01/84 012/84Status Report 02/84 011/84Pesetation of Energy Projects for the FouLi Five-Year Plan

(1983-1987) 05/85 036/85Improved Charcoal Cookstove Strate 09185 042/85Peat Utilization Project 11/85 046/85Energy Amssesnt 01/92 9215-BU

Capte Verde Enery Assmesst 08/84 5073-CVHousehold Energy Strategy Study 02/90 110/90

Comoros Enr Assmt 01/88 7104-COMCongo Energ A _t 01/88 6420-COB

Power Development Plan 03/90 106/90C6te d'Ivoire Energy A _t 04185 5250-IVC

Improved Bioms Utilization 04/87 069/87Power System Efficiency Study 1287 -Power Sector Efficiency Study (French) 02/92 141/91

Ethiopia Energy Asest 07/84 4741-ETPower Systen Efficiency Study 10/85 045/85Agiculturl Residue Briquetting Pilot Project 12/86 062/86Bagpsse Study 12186 063/86Cooking Efficecy Project 1V87 -

- 163-

Couhy AcMv*y Date Number

Gabon Ebq A meot 07/88 6915-GAlEe Gambia Eleq8y AtEeswnent 11/83 4743-GM

Solr Watfr Heating Rebofit Project 02/8S 030/8SSolr Photovoltaic Applications 03/8S 032/85Petroleum Supply Mlanagenet AEssista 04/85 035/85

Gbana Energy AuEent 11/86 6234-GHEnergy Raionalzatin the Industrial Sector 06/88 084/88Sawmill Residues Utilization Study 11/88 074/87

Guinea E=V A t 11/86 6137-GUI.GuineeBisms loery A _dnM 08/84 5083-GUB

Reommended Technical Assistance Ptrects 04/85 033/85Management Options for the Electric Power and Water Supply

Subsectors 02/90 100/90Power and Water Instittional Restmucting (French) 04191 118/91

Kenya Energy Assessnt 05/82 3800-KEPower System Efficiency Study 03/84 014/84

s Report 05/84 016/84Coal Conversion Action Plan 02/87 -Solar Water Heating Study 02/87 066/87Pni-Urban Woodfuel Development 10/87 076/87Power Master Plan 11/87 -

Lesotho EnerD Assemwent 01/84 4676-LSOLiberia E y Asessmt 12/84 5279-LBR

Rwo_neded Techicd Al iam Projects 06/85 038/85Power System Efficiency Study 12/87 081/87

Madagasar Energy Assmet 01/87 5700-MAGPower System Efficiency Study 12/87 07S/87

Malawi EnergyAsslt 08/82 3903-MALTechnical AsUsine to Tnprove the Efficiency of Fuelwood

Use in the Tobacco Idy 11/83 009/83Su"tw Rtport 01/84 013/84

Mali Energy A _ (Pch) 11191 8423-MUIslamic Republic

of Maluitana Energy A _et 04/85 5224-MAUHousehold Energy Staty Study 07/90 123/90

Mauritius Energy As e 12/81 3S10-MASStatus Report 10/83 008/83Power System Efficiency Audit 05/87 070/87Bagasse Power Potetial 10/87 077/87

Moznibique Bnert A _mment 01/87 6128-MOZHousehold Electricity Utilization Study 03/90 113/90

Niger EnergY ^_t 05/84 4642-NIRSt Report 02/86 051/86Improved Stoves Poect 12/87 080187Housold Energy Consevaon and Substitution 01188 082/88

Nigeria Energy A08 O/83 4440-UNIRwanda A 06/82 3779-RW

hErgV A _essnt (lig and Fte-h) 07/91 8017-RWStats Rot 05184 017/84Imprved Ckpcoal Cooksto Strat 08/86 059/86Improved Chao Podu Techiques 0287 065/87

-164

CoWry ActWty Date Numner

Rwanda Commercialization of Improved Charcoal Stoves andCarbonization TechniquesMid-Term Progrers Report 12/91 141/91

SADCC SADCC Regional Sector: Regional Capacity-Building Programfor Energy Sueys and Polcy Anayss 11/91 -

Sao Tomeand Principe Energy Assessment 10/85 5803-SP

Senegal E0ey Assem t 07/83 4182-SEStatus Rort 10/84 025/84Industrial Energy Conservation Study OSl85 037/85Preparatory Assistance for Donor Meeting 04/86 056/86Urban Household Energy Strategy 02/89 0! '/89

Seychelles Eaer Aesst 01/84 4 *SEYElectric Power System Efficiency Study 08/84 021/84

Sierra Leone Energy Assesent 10/87 6597-SLSomalia Energy Asssment 12/85 5796-SOSudan Management Assistance to the Ministry of Energy and Mining 05/83 003/83

Ene As 07/83 4511-SUPower System Efficiency Study 06/84 018/84Status Report 11/84 026/84Wood Energy/Foestry Fesibility 07/87 073/87

Swauiland Energy Assessment 02/87 6262-SWTania Energy Assessment 11/84 4969-TA

Pei-Urban Woodfue Feasibility Study 08/88 086/88Tobacco Cuing Efficiency Study 05/89 102/89Remote Sensng and Mapping of Woodlands 06/90 -Industri Energy Efficiency Technical Assisance 08/90 122/90

Togo E06agy Asement 06/85 5221-TOWood Recovery in the Nangbeto Lake 04/86 055/86POWer Efficiency Impovenmt 12/87 078/87

*J8a4ta EBAtgy Ausesoment 07/83 4453-UGStatus Report 08/84 020/84Ibstitutional Review of the Eney Sector 01/8S 029/85Energy Efficiency in Tobacco Curng Industry 02/86 049/86Fuelwood/Forestry Feasibiliq Study 03/86 053/86Power System Efficiency Study 12/88 092/88Energy Efficiency Imprr- ement in the Brck and Tile Industry 02/89 097/89Tobacco Curing Pilot Froject 03/89 UNDP Tenrinal

Zaire Energy Assmet 05/86 5837-ZRZambia EBnergy Assessmmt 01/83 4110-ZA

Status Report 08/85 039/85Eney Sector Institutional Reiew 11/86 060/86Power Subsector Efficiency Study 02/89 093/88Energy Statg Study 02/89 094/88Urban Household Energy Sty Study 08/90 121/90

Ziubawe Enery Assest 06/82 3765-ZIMPower System Efficiency Study 06/83 005/83Status Report 08/84 019/84Pw Sector Management Assistance Project 04/85 034/85Petoleum Management Asio 12189 109/89

-16S

CoWY Acdv* Dats Nwumber

Zimbabwe Power Sector Management Institution Building 09/89 -

Cbarcoal Utizaon Preaibility Study 06/90 119/90Iltrat Energy Stateg Evaluation 01/92 8768-ZM

EASR ASIA AND PACIFIC (EAP)

Asia Regional Pacific Household and Rural Energy Sem r 11/90 -

Chna County-Level Rural Energy Assessments 05/89 101189Fuelwood Forsty Preinveatment Study 12/89 105/89

Fiji Eiigy As rit 06/83 4462-PUIndonesda Enwg A sament 11/81 3543-IND

Status Report 09/84 022/84Power GCenation Efficiency Study 02/86 050/86Energy Efficiency in the Brick, Tile and Lime Industries 04/87 067/87Diesel Genting Plant Efficiency Study 12/88 09S/88Urban Household Energy Strategy Study 02/90 107/90Bioma Gafier Preinvetment Study Vols. I & U 12/90 124/90

Malaysia Sabah Power Sydem Efficiency Study 03/87 068/87Gas UtDiztion Study 09/91 9645-MA

Myannwr e Asset 06/85 5416-BAPapua New

Guinea Ergy Asemmt 06/82 3882-PNGStatus Report 07/83 006/83Enery Stratgy Pae - -

nstitutonal Review in the Energy Sectr 10/84 023/84Power Tariff Study 10t84 024/84

Solomnan IWands Eb"gy Am##sument 06/83 4404-SOLSouth Pacific Petroleum Trnsport in the South Pacific 05/86 -Thailand Enegy A ment 09/85 5793-TH

Rural Energy Iues and Options 09/85 044/85Accleratd Diemination of Improved Stoves and Charcoal Knlns 09/87 079/87Norteast Region Viage Forestry and WoodfuelsPreinveatment Study 02/88 083/88

Impact of Lower Oil Prices 08/88 -Coal Development and Utihzation Study 10/89 -

Tonga Energy Asuet 06/85 5498-TONVanuan EnQ Agy esn 06/85 5577-VAWestrn Samoa Energy AuEent 06/85 5497-WSO

SOUTH ASIA (SAS)

Etang1slesh Enerqgy AJamu*east 10/82 3873-EDPriority lnvestnet Program 05/83 002/83Stus Report 04/84 015/84Power System Efficiency Study 02185 031/85Small Scale Uses of Onas Prefiosibiity Study 12/88 -

- 166-

Corly Aed l& Di Nwnbr

nia Oppoftunties for Commercialimation of NonconventionaEnr Sysms 11/88 091/88

M_rashtm Bagass Enery Effiency Project 05/91 120/91Mini-Hydro Devolopment on Irigaon Dams and

Canal Drops Vols. I, II and m 07/v1 139191Nepal lVA m 08/83 4474-NEP

Status Report 01/85 028/84Pakistan Houseold ery A OS/88 -

- -- of Photovoltaic Proginms, Applications, and Markets 10/89 103/89Sri Lanka E0ergy Assessmen OS/82 3792-CE

Power System Loss Reduction Study 07/83 007/83Stus Report 01/84 010/84Industrial Energy Consevation Study 03/86 054/86

EUROPE AND CEN ARAL ASUI (ECA)

Portugal Energy Ameant 04/84 4824-POTurkey Ehg AEsnet 03/83 3877-TU

MIDDLE EAST ANID NORTH AFRICA (MNA)

Morneoo o Amomfmt 03/84 4157-MORStat"dus Report 01/86 048/86

Syria Energy Assma05/86 5822-SYRElectric Power Efficiency Study 09/88 089/88Energy Efficency Iimpvent n the Cmnt Sector 04/89 099/89Energy Effcimency Improvement i dte Fertilizer Sector 06/90 115/90

Tunisia Fuel Substitution 03/90 -

Yemen EnergAy h mes t 12/84 4892-YAREnergy Investment Priorities 02/87 6376-YARHousehold Energy Sfttegy Study Phase I 03/91 126/91

LATIN AMERICA AND TIRE CARIBBEAN (LAC)

LAC Regional Regional Semiar on Elmec Power System Loss Reductionin the Caribbean 07/89 -

Bolivia Enersy m 04183 4213-BONatonal Energy Plan 12/87 -Nationdl Energy Pln (Spanish) 08/91 131/91La Paz Privat Por Technical Asdstance 11/90 111/90Natund Gas Disuibution: EBonomics and Reguaiton 01/92 125/92Prefeadibility Evaluaton Rurt Elctnficcatin and Demand

04/91 129/91Caie Enurgy Sectr Review 08/88 7129-CHColombia y St12186 -Cota Rica E=V Asont 01/84 4655-CR

;n_I Tedrl AsWs_e Poftects 11184 027/84Forst Reidues Utiliztion Study 02/90 108/90

- 167 -

Couon AcdWy Dae Number

Dominican E051gy Amsement OS/91 8234-DORepubb

Ecuador Eneg sment 12/85 5865-ECEkYay Stodqgy Fb"8e I 07/88 -EnaVgy Sbadegy 04/91 -

dati E0e6g An"t 06/82 3672-HAStatus Report 08/85 041/85

Honduras Energy Am M 08187 6476-HOYetxdeum Supply Managernent 03/91 128/91

Jamaica Emr Ammum 04185 5466-JMPetroeum Pocurement, Refining, and Disribution Study 11/86 061/86Energy Efficiency Building Code Phase I 03/88 -

EneVgy Efficuocy Standards and Labels Phase I 03/88 -

lla ye et bnmtion,nad System Phsse I 03/88 -

Chaucoal Production Project 09/88 090/88FIDCO Sawmill Residues Utilization Study 09/88 088/88

Mexico lImroved Carcol Production Within Forestf ofr ths Stat of Veracruz 08/91 138/91

Paunam Power System Efficiency Study 06/83 004/83Paraguay Energy h mes t 10/84 5145-PA

Recommended Technical Aistance Projects 09/85 -

Status Reiport 09/85 043/85P-eu Enwy AesncM 01/84 4677-PE

Status Report . 08/85 040/85Proposal for a Stove Disseinaion Prtogam in the Sierra 02187 064/87Enegy Stra 12/90 -

Saint Lucia Energy Ammmunt 09/84 5111-SLUSt Vincent andthe Grenadines Energy sessnt 09/84 5103-51W

Triidad andTobago Enfg Assesiat 12/85 5930-TR

GLOBAL

Energy End Use Efficiency: Research and Stategy 11/89 -

Guideines for Utility Customer Mlaemet andMeteing (Englsis and Spanish) 07/91 -

Women and Energy-A Resource Guidemm International Network: Policies and Experience 04/90 -

Assessment of Pesonad Computer Modebs for EnergyPlning in Developing Conties 10/91 -

IBRD 23592

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